bluuebunny/crossref_metadata_2025 huggingface dataset:
Stress Estimation at the Otway CO2 Storage Site, Australia
Authors: Bérard T. , Sinha B. K. , Van Ruth P. , Dance T. , John Z. , Tan C.
Published: October 2008

We present an estimation of the full stress state between 0.5 and 2.1 km depth at the Otway CO2 storage pilot site, Australia, where the Cooperative Research Centre for Greenhouse Gas Technologies is conducting a large-scale demonstration project. This estimation is the first step of a geomechanical study on seal integrity. One principal stress is assumed vertical and of magnitude equal to the weight of the rock above, calculated from the density log data. The vertical stress gradient is on average 22.01 MPa/km. Extended leak-off test data, a borehole wall electrical image and dipole sonic log data in the CO2 injector CRC-1 are used to constrain principal horizontal stress orientation and magnitudes. Consistency of the stress model is then checked against the occurrence of breakouts using a mechanical earth model built along CRC-1 well. We conclude that the maximum horizontal stress direction is oriented N141 +/− 9°E. To first order, principal horizontal stress magnitudes both follow a linear trend with depth. Results indicate minimum horizontal and maximum horizontal stress gradients on average equal to 15.98 and 18.13 MPa/km, respectively, corresponding to a normal stress regime.
Preventing Annular Gas Flow in Conjunction with 2 Stage Cementing
Authors: Brooks Robert , Newberry Jack , Cook Paul , Wendlinger Franck
Published: October 2008

The most important purpose of primary cementing is to seal the annulus in order to eliminate communication between subterranean zones and the surface. Drilling through gas formations poses unique risks such as annular gas flow. Annular flow related to poor cementing of large diameter surface casing has been identified as one of the most frequent causes of well control incidents. Many primary cementing jobs fail to stop interzonal communication, and poor cement bonding has been credited with the most significant cause of annular casing pressure in outer casing strings. Statistics worldwide indicate there are thousands of wells with sustained casing pressure that potentially lose hydrocarbon reserves, or leak gas at the sea floor.

Annular gas flow during, and after, cementing is a frequent problem in areas where oil and gas reservoirs are the primary producing reservoirs, shallow gas formations are present, and leak-off tests are not regularly performed. When zonal isolation in gas wells is not achieved, gas can migrate behind the casing, thus charging shallower formations, which become a costly problem when they are drilled into unexpectedly. Several techniques are currently used to control annular gas migration with each delivering varying degrees of success

These methods involve drilling processes, cementing systems, and mechanical barriers. This paper focuses on the use of an inflatable casing annulus packer (CAP) to seal the annulus in conjunction with a cementing port collar (PC) above the gas migration source. If the primary cement job does not achieve the required displacement efficiencies, and satisfactory results, a second stage cementing option using the port collar is still a possibility.

As an ongoing development to allow for the reduction of the number of casing strings in a well, integration of a metal-to-metal (MTM) sealing cementing port collar and CAP in a premium production casing string, with MTM sealing connectors, is used. This light architecture well design effectively reduces overall well costs in addition to improving HSE issues.

By utilizing this approach no gas migration has been detected to date in over 357 wells completed using casing annulus packers and port collars. Based on prior experiences and costs associated with remediation of a well with annular gas flow, the mechanical control technique has effectively reduced the overall well costs in addition to drastically improving HSE issues.
Study on Minimum Air Flux for In-situ Combustion into Light Oil Reservoir
Authors: Takabayashi Katsumo , Onishi Takeshi , Okatsu Koumei , Maeda Haruo , Moore R. Gordon , Mehta S. A. (Raj) , Ursenbach Matthew G.
Published: October 2008

In-situ combustion projects in heavy oil reservoirs were started early part of the last century. The number of projects was increasing toward 1960s. More than 120 projects were carried out in U.S. at that time. After 1970s, it plunged to less than one-tenth. But in the middle of 90s, it began to increase again. The main reason for this rise was an increase in-situ combustion projects in light oil reservoirs and recently they have been increasing.

Since 1999, our study of the light oil reservoir from the Minami-Aga oil field in Japan has continued. Now we focus our attention on minimum air flux which is needed to sustain a combustion front. The minimum air flux will be used to design an air compressor for a pilot-project.

A discussion of minimum air flux for heavy oils was published by Nelson and McNeil5. It is believed that a mechanism of combustion for the light oil is different from the heavy oil. It is also believed that the light oil's combustion front is less stable than the heavy oil's. Therefore in our case to estimate the minimum air flux, it might be better to take a different way. In this paper, a thermal simulator was used to estimate the minimum air flux. Prior to a simulation study some High Pressure Ramped Temperature Oxidation (HP-RTO) tests with our oil were carried out to obtain combustion parameter. A reaction model in the thermal simulator was obtained based on the HP-RTO tests results.
Challenges in Completing Long Horizontal Wells Selectively
Authors: Ritchie Barry , Abbasy Imran , Pitts Michael , White Brendan , Jaafar M. Rushdan
Published: October 2008

Although drilling technology is now able to deliver ultra-long horizontal wells, completion technology has been slower to evolve. Running long liners, effective stimulation and completions are some of the areas that require more attention.

The paper discusses some of the challenges in the development of the Al Shaheen reservoirs offshore Qatar and how they were overcome. Some of these wells have a step-out in excess of 30,000 feet with a TVD of 3,100–3,500 feet and thus they offer some unique challenges.

Running and cementing liners to these depths is difficult and some of the methods to effectively achieve this are discussed. Perforating guidelines are presented that allow sand control without having to resort to conventional sand control practices. Stimulation of such long reservoir sections is a particular challenge and a fine balance must be struck between acid coverage and cost, both for barefoot and perforated intervals. The so-called Q-CAJ technique of acid distribution is presented, which has allowed acceptable stimulation despite these conditions. The technique also offers opportunities to stimulate long horizontal boreholes more effectively and at lower cost.

Some of the wells are completed with multi-zone selective completions, which push the design limit of equipment. A number of such intelligent wells have been completed successfully and more aggressive wells are planned. In order to optimize the development cost, dual-lateral wells have also been drilled with complete control over each lateral. Discussed are some of the underlying completion techniques such as running completion in stages, use of mechanical latches, hydraulic control line wet connects, interval control valves and limitations imposed by control lines. The paper concludes with some of the challenges that have yet to be overcome.
Successful Application of Horizontal Well Completions for Development of Low Permeability Gas Reservoirs in a Complex Fluvial Deltaic Environment – A Case Study
Authors: Hazman Harry Alam , Damayanti Shinta , Wijanarko Andre , Arifin Zainal , Rahardjo Heriadi Buhron , Nikijuluw Robert , Sable Gary J. , Narayanan Ram K. , Schmohr Donn , Rylance Martin
Published: October 2008

VICO Indonesia is the operator of the Sanga-Sanga Production Sharing Contract located onshore of the Mahakam delta, East Kalimantan, Indonesia. The PSC has produced over 70% of the OGIP (original gas in place). The fields are relatively mature with the remaining gas resources locked up in either pressure depleted reservoirs or in low permeability reservoirs where conventional techniques have not been very effective in depleting these resources. During 2006, VICO decided to perform a pilot development of the larger/tighter reservoir tanks, utilising the horizontal completion technique as the preferred completion approach.

To date VICO has successfully drilled and completed 5 horizontal wells, one in the Semberah field (S77H) and four in the Nilam field (N228H, N230H, N238H & N240H). The Semberah S77H well was drilled and completed in 2006 at a relatively shallow depth (~ 8000 ft.TVD.SS), in order to demonstrate the applicability of horizontal drilling technology within VICO. The four subsequent wells were drilled in the Nilam field, to depths of ca. 12,500 ft.TVD.SS. The N228H & N238H wells were drilled to test the productivity of horizontal wells at higher reservoir pressures; where condensate banking was thought to be a contributory factor to the dramatic transient and low deliverability seen from conventional vertical wells. Whereas the N230H and N240H wells, were drilled to test the productivity of horizontal completions in the depleted tanks where condensate banking may not be such a significant factor. All five of the wells are currently producing at relatively stable rates with significantly less decline, when compared to conventional offset wells. The initial gas production rates, that were achieved, were significantly higher than conventional wells producing from the same reservoirs and the total reserves recoverable per well are estimated to be 2 – 3 times higher than a conventional well.

The paper will describe in detail the candidate selection criteria, well design, well placement, drilling risks, tool reliability and the challenges steering a horizontal well in a geologically complex environment with high degree of reservoir uncertainty.
Using Chemical Tracers for Flow Profiling a Subsea Horizontal Well with an Open Hole Gravel Pack Lower Completion: Field Results
Authors: Bakhshi Ali , Scaife Peter , Mickelburgh Ian
Published: October 2008

This paper presents the first case study on using chemical tracers for flow profiling a subsea horizontal well with an open hole gravel pack lower completion in Enfield field, Australia. The principle of the technology involves positioning a number of different tracer materials, each at specific locations along the length of lower completions, prior to lowering downhole. The tracers are selected to be soluble in either crude oil or water. Upon well start up, oil samples are taken at the surface over a short period of time. These samples are analysed to determine tracer presence. The presence of one or a combination of unique tracers within the oil sample, along with the known location of each tracer downhole, allows qualitative information to be generated about fluid flow in the well.

Chemical tracers for flow profiling were chosen for ENA03L1, an oil well intersecting a number of fault blocks in the south of the Enfield field to: Provide direct proof of fluid flow from different fault blocks;Improve understanding of well clean up of a horizontal well, especially the contribution from the toe of the well; andDetect the location of water breakthrough.

Results showed that within four hours of the initial clean up, all oil soluble tracers were detected, providing positive confirmation that the intervals tagged, including the toe of the well, were contributing to the overall production.

Using tracers for flow profiling horizontal well provides the following benefits: Enables flow position to be verified in long horizontal wells; andComparatively inexpensive when compared to horizontal well production log costs.

This case study recounts the design, installation, analysis, results and subsequent learnings of the project.
Integrating 4D Seismic Data with Production Related Effects at Enfield, North West Shelf, Australia
Authors: Ali Amna , Taggart Ian , Mee Benjamin , Smith Megan , Gerhardt Andre , Bourdon Laurent
Published: October 2008

The Enfield field has a 160 m oil column located between a medium sized gas cap and a water/leg aquifer system. Enfield is undergoing an active water-flood utilizing both up-dip and down-dip water injection. The water-flood reservoir management of such a field requires timely information concerning reservoir pressures, water-flood sweep and movement of gas and water contacts. Conventional reservoir monitoring practice obtains this information by monitoring at the wellbore. Such approaches require significant time and water-cut development to determine how the reservoir and water-flood is performing and provide little spatial information as to how the water-flood is affected by faults, preferential pathways and structural variation. 4D seismic methods represent a powerful tool to assist reservoir management. This work describes the planning, implementation of an early 4D program for the Enfield water-flood and history matching process. Pre-development feasibility work indicated that Enfield had rock properties favourable for 4D monitoring as reservoir sands are acoustically soft and identifiable with seismic amplitudes. Post-production, early 4D monitoring has provided unique and timely insight into water movement both within the reservoir and through active fault networks that wellhead data alone would not provide. This work has shown the benefit of 4D in the following areas; tuning of injected water flows to a northern fault/aquifer system, locating new injector producer pairings, improved utilization of geologic and seismic barrier and baffle features into the history matching process and finally showing how the seismic response to up-dip water injection, around a key injector, was more subtle and supported the choice of imbibition relative permeability relationships and trapped gas saturations. Validation of insights was provided by the use of synthetic seismic modeling of simulation results.
Successful Field Application of Novel, Non-Silicone Antifoam Chemistries for High Foaming Heavy Oil Storage Tanks in Northern Alberta
Authors: Wylde Jonathan J
Published: October 2008

Substantial foam formation was being experienced by two operators in several heavy oil leases in Northern Alberta. This 10 – 12 API crude had a large foaming potential and unique foam formation mechanism. Crude oil passed from the wellhead, via a short flowline to a pair of hydrostatically balanced and heated storage tanks. The storage tanks heated the crude oil from approximately 50°C to 85°C and in doing so, caused gas breakout and degassing which resulted in the formation of a thick, persistent foam in the top of the tanks. The foam would enter the transportation trucks and end up at the local battery and create carry over and separation problems in the process systems.

Silicone antifoam products were not acceptable due to both their poor environmental profile and also the influence these large molecules had at the refinery where the crude oil was shipped for (predominantly) asphalt manufacture.

A wide range of chemistries were tested including phosphate based products, ethoxylated and propoxylated esters, polyethylene glycol esters and oleates, alcohols, fatty alcohols and ethoxylated and propoxylated alcohols. One of the major challenges detailed in this paper is that all products had to be freeze protected to −40°C. This was significant due to many anti-freeze chemicals affect the efficacy of antifoam chemicals.

This paper details evolution of testing leading to the field application of this combined defoamer / antifoam chemistry. Initial laboratory screening is included which describes a unique laboratory test method designed to mimic more accurately the foam formation environment in the field. The paper goes onto illustrate the field trial evaluation as well as the case histories of full field implementation of the highest efficacy products.
Design and Implementation of a Caustic Flooding EOR Pilot at Court Bakken Heavy Oil Reservoir
Authors: Xie J. , Chung B. , Leung L.
Published: October 2008

The Court Bakken heavy oil reservoir (17 °API) in Saskatchewan has been under successful water flooding for many years. Laboratory studies have indicated that caustic flooding can enhance heavy oil recovery significantly after water flooding. This paper describes design and implementation of the first caustic flooding pilot in a heavy oil reservoir of this viscosity range in the Western Canadian basin. It reviews results of laboratory studies and a single well test. It also discusses challenges experienced at Court during the early piloting phase.
Development of a Higher-order Finite Volume Method for Simulation of Thermal Oil Recovery Process Using Moving Mesh Strategy
Authors: Ahmadi Mohammad
Published: October 2008

Numerical simulation of thermal recovery processes like steam injection often involves localized phenomena such as saturation and temperature fronts due to hyperbolic features of governing conservation laws, Treating more efficiently convective terms could help to diminish spurious oscillation and/or numerical dispersion and better tracking of discontinuity shocks. But in regions near the shock numerical dispersion can only be removed by the use of very fine uniform grids with many grid blocks. To avoid expensive solution of such a finely girded domain, we develop a moving mesh approach combined with higher order up-winding schemes.

Numerical solver here have been employed is Finite volume method. A MMPDE(moving mesh PDE) is solved associated with physical PDE's of steam injection process in order to relocates the mesh nodes to concentrate them in regions of sharp discontinuity and Equi-distribute a measure of error-estimate (monitor function) over the meshes. Solution will advance more rapidly on course meshes and fluxes at the coarse-fine grid interfaces are refined to guarantee mass conservation.. Since the region surrounding the sharp discontinuity and requiring high resolution consists of only a small fraction of the entire domain, prescribed locally time stepping results in a great saving in computational time. Specific features of moving mesh methods like monitor-function smoothing, control of mesh widths and readjustment of solutions further to mesh movement are addressed. Numerical experiments are carried out to demonstrate the efficiency and robustness of the proposed method in 1-D and 2-D. However numerical results for moving coordinates are compared with those obtained from simulation on non-adapted mesh framework. Preferences of higher-order solvers over lower-order ones in terms of shock capturing is being investigated.. Although we have limited our modeling to steam flooding process, but simulation demonstrates main features of our approach, applicable to other EOR processes such as VAPEX, SAGD, and In Situ Combustion Process.
Reservoir Characterization and Monitoring of Cold and Thermal Heavy Oil Production Using Multi-Transient EM
Authors: Engelmark Folke
Published: October 2008

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

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

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

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 < 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

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

The 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

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

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

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

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

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.
Mechanical Evaluation of a New Sand Control Screen for SAGD Applications
Authors: Woiceshyn Glenn , Toffanin Ezio , Xie Jueren , Wagg Brian , Fan Chengye
Published: October 2008

Steam assisted gravity drainage (SAGD) wells typically require the deployment of an open hole completion combining sand control with adequate mechanical strength to withstand: 1) aggressive installation loads—compression, torque, bending—that are characteristic of shallow horizontal wells, and 2) severe operational loads—tension, compression, collapse, burst—caused by a combination of high temperature steam injection and formation collapse around the completion.

Historically, slotted liners have been used in Western Canada, primarily because of low cost relative to wire-wrapped screen (WWS) or premium mesh screens. However, slotting base pipe can significantly weaken its mechanical strength, particularly in torsion and collapse, and the slot width can change as the liner deforms under certain load conditions. Reported incidents of mechanical failure and loss of sand control of slotted liners in SAGD wells have generated interest among operators to investigate alternative technologies.

A new sand screen has been developed that involves flush-mounting and securing 25.4 mm diameter fusion bonded metal laminate (FBML) cartridges/discs directly into the base pipe wall. The open flow area of the screen, which can be as high as 20% (versus 2.5% for slotted liner), is dictated by the number of inserted discs (holes) per foot. For an equivalent open flow area, drilling holes in the base pipe is less detrimental to the mechanical strength of the liner than cutting slots. This new geometry results in a sand screen that is cost competitive to slotted liner on a same-open-flow-area basis, significantly stronger, and comparable to a premium mesh screen in terms of sand retention performance.

To independently quantify the mechanical strength and integrity of this new screen for SAGD, an extensive Finite Element Analysis study was performed on 177.8 mm (7"), 38.7 kg/m (26 lb/ft), L80 base pipe for two different hole densities and various single loads, combined loads and thermal cycling. The results, as presented herein, demonstrate that inserting FBML discs into base pipes does not significantly weaken it compared to cutting slots. A stand alone screen (SAS) with almost four times the open flow area of a slotted liner has significantly more torsion and collapse strengths.
Maximizing Heavy-Oil Recovery by Containing Steam through Optimized Cementing
Authors: Ravi Kris , Hunter Bill , Kulakofsky David
Published: October 2008

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.
The Progressing Cavity Pump Operating Envelope: You Cannot Expand What You Don't Understand
Authors: Noonan S. G.
Published: October 2008

Progressing cavity pumps (PCP) have been the preferred method of lift for cold heavy oil production for years. They were generally not considered a complex technology, unlike electric submersible pumps for example, and this resulted in many misapplications and poor performance.

Until the PCP industry started to push the envelope in terms of landed depth, production volumes, gas handling, viscosity and aromatics, that testing programs emerged to understand the science behind PCP performance under various conditions. This paper will describe some of the recent findings from these test programs that will help to better select and design a PCP system for heavy oil. Some of this work includes understanding gas handling capabilities, rod string torsion, elastomer swell, metallic stators, and the effects of speed and rotor - stator fit on PCP run life.

The PCP industry has also been plagued with the lack of a "common language" which makes communication of lessons learned and data sharing difficult. This paper will describe the efforts of a group of operating companies to standardize nomenclature and data parameters to facilitate analysis and benchmarking to identify areas for improvement and gaps for technology advancement. This paper will also provide information from the group of PCP users and manufacturers that worked together since early 2006 to create comprehensive international standards and recommended practices for the manufacturing and testing of these pumping systems.