bluuebunny/crossref_metadata_2025 huggingface dataset:
Application of the PRMS to Coal Seam Gas
Authors: Barker Geoffrey J
Published: October 2008

In March 2007, the SPE Board, along with the WPC, AAPG and SPEE approved the new Petroleum Resources Management System (PRMS). The PRMS contains a set of definitions, standards and guidelines for the classification of conventional and unconventional petroleum resources.

This paper discusses the importance of coal seam gas as a global resource and presents an overview of the coal seam gas industry in Australia. The basic principles of the PRMS are presented and the current practices used by the industry to classify and categorise reserves and resources are summarised. Unconventional petroleum resources require different evaluation and development techniques and have their own uncertainty characteristics which can affect reserves booking. The scale of development projects may also be very different for 1P, 2P and 3P reserves categories and consequently each of these may require considerably different capital investment.

Industry practice indicates that there may be some confusion about the application of the PRMS to coal seam gas properties and therefore it is the objective of this paper to assist stakeholders to correctly and consistently apply the PRMS standards. This is of particular importance as the development of coal seam gas is going through an exponential growth phase in the drive to meet record demand.
Acid Gas Removal System for Tangga Barat Cluster Gas Development – Case Study
Authors: Muhamad Suhana , Hassan Nur Hayati , Sabri Harris Abd Rahman , Ariff Izrul Akmal M , A Karim A Hamid , Hong Teh Yat
Published: October 2008

This paper discusses challenges in developing high CO2 gas fields based on project execution of Tangga Barat Cluster, the very first high CO2 gas cluster being developed offshore Peninsular Malaysia by PETRONAS Carigali. Discussion focuses on the intricacy and challenges specifically on designing offshore facilities to accommodate one of the largest Acid Gas Removal System (AGRS) offshore. It addresses steps and considerations in decision making, reaching the most advantageous solutions, in designing the AGRS as well as the overall facilities which involves the required supporting utilities. Data from well tests, FORGAS simulations, and process model from HYSYS among others shall be woven in the discussion.

The discussions on the executed design strategy shall benefit future high CO2 gas fields projects by providing at the very least, a design guidance. The paper highlights the modus operandi in ensuring the final gas specifications of 8 mole% CO2 is met while accommodating different AGRS technology provider utilities requirements.

The membrane technology was identified for the bulk CO2 removal of 35% down to 8% CO2 in sales gas. Due to distinctive differences in the technology provider's removal processes, several factors were considered in designing the process utilities, electrical, mechanical and structural aspect of the system. The overall project economics for hydrocarbon losses in both single and two stage systems were assessed to reach a decision with acceptable losses. The operating conditions of the AGRS were optimized through the analysis of the reservoirs pressure and the booster compressor optimization.

In view of the high development costs associated with these acidic fields, it is the author's intent to contribute, to some degree, lessons learnt in the planning, design and execution for future acidic field developments. It is aspired that through costs, time and resources optimization, the overall project economics can be improved.
A Case History of Heavy Oil Separation in Northern Alberta: A Singular Challenge of Demulsifier Optimization and Application
Authors: Wylde Jonathan J , Coscio Steven
Published: October 2008

This case history tracks the continual improvement cycle for the fluid separation process of a heavy oil / oil sands production facility in Northern Alberta over a period of three years. The major challenge posed by the operator of this 13 - 16° API crude oil was to move away from injection of two separate demulsifier formulations to a single product. This was not an easy task due to the very different conditions that existed at the two injection locations. The first location was at a series of injection points upstream of the gathering stations, prior to separation, where temperatures could reach sub-zero conditions and the second was at the battery receiving facility where heating increased temperatures to 100°C. Water cut and shear were also very different and the operator required a very strict 0.2% BS&W on the crude exiting any of the four treater tanks; to further complicate issues crude oil viscosity ranged from 500 - 5000 cP.

A unique bottle testing method was developed and used to simulate the field conditions as accurately as possible. Details are given on the chemistry of the individual components of the demulsifier determined to be so crucial to adequate performance and how this was optimized in the field after being identified from the bottle tests.

Results show how careful consideration needed to be given to the concentration of the demulsifier bases in the blends and the curious observation that dilution of the final product made a big difference to the final performance in the field. Elaboration is given on potential mechanisms explaining the dilution effect and the paper goes on to conclude how careful design of field testing followed by field implementation can indeed solve complex separation issues and address individual well, battery and field requirements.
Successful Field Application in Continuous DTS Monitoring Under Harsh Environment of SAGD Wells Using Improved Optical Fiber Technology
Authors: Kaura Jiten , Sierra Jose
Published: October 2008

The use of optical fibers in the oil and gas industry is becoming more viable for several permanent monitoring applications, such as distributed temperature sensing (DTS) and optical pressure transducers. However, long-term performance of fibers, especially at elevated temperatures, is still an issue yet to be fully resolved. This problem is critically important in steam-assisted gravity drainage (SAGD) applications, where wells operate in extreme conditions of high temperatures, often exceeding 250°C, as well as in high pressures within a hydrogen-rich environment.

Optical fiber performance is seriously affected by many factors, including:

Hydrogen ingression Thermal resistance of the materials Mechanical resistance of the fiber

Exposure of optical fibers to hydrogen changes the performance of the fibers through what is referred to in the industry as "hydrogen aging" or "hydrogen darkening." Hydrogen darkening is increased absorption or light loss due to various chemical species in the glass fiber resulting from the presence of hydrogen.
Thermal Efficiency and Acceleration Benefits of Cross SAGD (XSAGD)
Authors: Stalder John L.
Published: October 2008

Two characteristics of XSAGD that accelerate bitumen recovery and improve thermal efficiency are discussed in this simulation study.

First, it is well understood that the significant oil mobilization process during SAGD occurs at the periphery of the steam chamber where steam transfers heat to the reservoir rock and bitumen. However, once the SAGD steam chamber is well established, it tends to have a low surface area to volume ratio due to its generally cylindrical geometry. In contrast, XSAGD tends to have a higher ratio of surface area to volume once its multiple steam chambers are well established. This allows a given amount of heat injected as steam in XSAGD to contact bitumen faster than the same amount of heat injected in SAGD after the initial steam chamber formation period.

Second, fluids moving through the parallel horizontal wells in SAGD follow pathways that remain relatively stable in temperature throughout the life of the operation. Conversely, fluid flow through the perpendicular arrangement of wells in XSAGD exposes cooler portions of the reservoir to conduction heat transfer from hot steam flowing in the injectors or heated bitumen and steam condensate flowing in the producers. This heat transfer accelerates heating in the reservoir and reduces the heat that is produced back to the surface so that more of the injected heat is beneficially applied to the reservoir compared to SAGD. The heated areas close to the wells accelerate the development of lateral displacement pathways promoting more rapid spreading of the steam chambers in XSAGD.

The increased thermal efficiency and acceleration of recovery of XSAGD are more pronounced for thinner pay and for lower pressure operation compared to SAGD. However, XSAGD retains some economic advantage even as pay thickens and injection pressure increases.
Offshore Connectivity and Ultra-Long Tiebacks Solutions for Oil and Gas
Authors: Lecroart A. , Michel R. , Odier J. P.
Published: October 2008

The Oil and Gas Industry is forced to go in deeper and deeper water further and further offshore to find new oil or gas. For the Oil Co., this means operating offshore facilities safely, reliably and efficiently in harsh environment far from shore.

Alternative development scenarios involve the implementation of subsea facilities and ultra-long tiebacks.

At the same time, the industry is placing more and more emphasis on integrated operations driven from onshore control centres.

Highly reliable communications solutions are required to enable Oil Co to fulfil these objectives. Large bandwidth and low latency links between the offshore facilities and the shore are essential as well as ubiquitous communications to all company personnel and contractors engaged in the offshore field development area.

This paper describes the overall solutions to address these needs. It reviews available technologies to address connectivity and communications needs that are particularly suited to deployment in offshore environment, in particular submarine fiber optics and radio including Wimax, and present Alcatel-Lucent vision on the application of these technologies to respond to the needs of the Oil and Gas Industry. The paper describes in more details, for both offshore connectivity and ultra-long tiebacks, possible optical data and electrical power architectures together with the products and their heritage, including the submarine 10kW DC-DC power converter, optical in line repeater, sub sea transponder and last mile connections. The hardware breakdown structure, technology gaps and solution costs are reviewed and discussed.
A New Flooding Scheme by Horizontal Well in Thin Heavy Oil Reservoirs
Authors: Liu Huiqing , Zhang Hongling , Wang Zenglin , Wang Man
Published: October 2008

It is possible to set a special packer within the long completion horizontal interval to establish an injection zone and a production zone, and a new flooding scheme of simultaneous injection and production in a single-hole horizontal well drilled for developing thin marginal heavy oil reservoir or small block reservoirs or offshore reservoirs. In field practice, the fluids injection rate can be controlled with either concentric or parallel tubing strings. Reservoir numerical simulation was used to determine the formation thickness lower limitation for different viscosity reservoir and the optimum time to start steam flooding after steam soak by economic oil/steam ratio. The optimum time to start steam flooding is at the 7th cycle. There exists a peak recovery efficiency of steam flooding when the length of separation section ratio is 0.15-0.2. Oil recovery rate can be enhanced by increasing steam injection rate, but pressure difference also increase and the pressure difference increases sharply, and separation section by packer will not be in a stable state in the steam flooding process. A steam injection rate of 2.4t/(d.ha.h) was suitable for steam flooding under practical injection-production conditions. All the results could be useful for the guidance of steam flooding project.
Effect of Ultrasonic Intensity and Frequency on Oil/Heavy-Oil Recovery from Different Wettability Rocks
Authors: Naderi K. , Babadagli T.
Published: October 2008

Using acoustic energy in enhanced oil recovery is not a new idea but yet is categorized as an unconventional method. In previous studies at our institution, the effect of ultrasonic radiation on capillary imbibition recovery of light oil from a water wet medium was widely investigated. Upon promising results, the study was extended to more challenging cases such as oil wet matrix (with and without initial water) and heavy oil. The effects of ultrasonic intensity and frequency were also included.

Cylindrical sandstone cores were placed into imbibition cells where they contacted with aqueous phase. Each experiment was run with and without ultrasonic radiation keeping all other conditions and parameters constant. The experiments were designed to investigate how the presence of initial water saturation can affect the recovery (Swi=0 to 40%), and also how the recovery changes for different oil viscosities (35 to 1600 cp). Furthermore, the samples were tendered oil-wet by treating with dryfilm to quantify the effects of wettability. In addition, the specifications of acoustic source such as ultrasonic intensity (45 to 84 W/ sq cm) and frequency (22 and 40 kHz) were also changed. An increase in recovery was observed with ultrasonic energy in all cases. This change was more remarkable for oil-wet medium. The additional recovery with ultrasonic energy became lower as the oil viscosity increased.

The results revealed that the ultrasonic intensity and frequency are very critical on the performance. This is a critical issue as the ultrasonic waves have limited penetration into porous medium and the intensity reduces while penetrating into porous medium. This is a major drawback in commercializing this promising process for well stimulation. Hence, we designed a set-up to measure the ultrasonic energy penetration capacity in different media, namely air, water, and slurry (sand+water mixture). A one-meter long water or slurry filled medium was prepared and the ultrasonic intensity and frequency were monitored as a function of distance from the source. The imbibition cells were placed at certain distances from the sources and the oil recovery was recorded. Then, the imbibition recovery was related to the ultrasonic intensity, frequency, and distance from the ultrasonic source.
Injection of Multi-Azimuth Permeable Planes in Weakly Cemented Formations for Enhanced Heavy Oil-Recovery
Authors: Hocking Grant , Cavender Travis , Schultz Roger L.
Published: October 2008

Stimulation of weakly cemented formations is not the same fracturing process that occurs in hard rocks because the weak formations have minimal strength and basically zero fracture toughness. It has been demonstrated conclusively that vertical planes can be injected in weakly cemented formations with control of the plane's azimuth, and multiple planes can be injected at differing azimuths, both sequentially and simultaneously in a single well. Laboratory and near-surface experiments involving injection from a perforated casing have yielded random injected geometries that are not repeatable and do not develop a planar-injected feature. On the other hand, if the casing is dilated during the injection process, repeatable consistent vertical planar-injected geometries are formed with control of the azimuth of the injected planes. These experiments have been conducted in laboratories at numerous shallow-field sites involving excavation of the injections and at deeper field sites with the injected geometry determined by real-time imaging using the active resistivity method. The specialized casing system is conventionally drilled and cemented in place, sub-surface resistivity receivers installed, the casing dilated during injection, and the subsequent injected geometry imaged in real-time during the injection process. The application has field demonstrated both simultaneous and sequential multi-azimuth, vertical planar injections from a single casing horizon. The method has significant potential in soft rock formations for production enhancement in both shallow gas and shallow heavy oil reservoirs. This paper presents field injection experiments of multi-azimuth, injected, vertical planar geometries in a variety of weakly cemented formations and describes the application of the method to shallow petroleum soft rock reservoirs, especially for thermal and solvent recovery of heavy oil.
Utilizing Natural Gas Huff and Puff to Enhance Production in Heavy Oil Reservoir
Authors: Wenlong Guan , Shuhong Wu , Jian Zhao , Xialin Zhang , Jinzhong Liang , Xiao Ma
Published: October 2008

L Block is a super-deep heavy oil reservoir with the degassed oil viscosity of 9,680∼12,000mPa.s @50☐, 2800∼3300 m deep with normal pressure system and 80∼95☐ in the reservoir. The GOR is 12m3/m3 and the initial bubble point pressure is only 4MPa. High oil viscosity and low flowability result in low production and rapid decline of primary development. This paper will review mechanisms, feasibility and pilot test of utilizing natural gas huff and puff to enhance production in L Block. Firstly, the paper will detail the lab experiments which include the conventional PVT and unconventional PVT. The conventional PVT shows that the natural gas dissolved in the oil can greatly decrease oil viscosity by 1∼2 orders of magnitude and enhance the flowability in one hand, in other hand, it can large the volume coefficient and add the elastic energy. The unconventional PVT shows that the heavy oil can effectively entrap the gas for more than several hours because of its high viscosity. There exists a pseudo bubble point pressure far lower than bubble point pressure in the manmade foamy oil, which is relative to the depressurization rate. Under the condition, the elastic energy could be maintained in a wider pressure scope than natural depletion without gas injection. Secondly, the paper will introduce a special experiment apparatus which can simulate the process of gas huff and puff in the reservoir. The huff and puff experiment shows that in this process the foamy oil can be seen and most of oil flows to the producer in pseudo single phase, which is one of the most important mechanisms of enhancing production. Finally, the paper will brief the pilot test of single well, which shows that the oil production is increased to 5∼6 m3/d from 1∼2m3/d by natural gas huff and puff and the stable production period is prolonged to 91days in the first cycle and 245 days in the second cycle from 5∼10 days before huff and puff.
Thermal Transient Analysis Applied to Horizontal Wells*
Authors: Duong Anh N.
Published: October 2008

The effectiveness of heat injection into a target formation has a great impact on the efficiency of bitumen and heavy oil recovery and energy savings under many steam heating processes such as the startup phase of SAGD (Steam Assisted Gravity Drainage) (Butler 1991). However, this parameter is hard to calculate due to many unknown variables such as variations in operational conditions and steam saturation along the horizontal wellbores, heat return rates, and losses to the vertical section above the target formation.

This paper proposes a new technique to estimate cooling time and formation thermal diffusivity by using thermal transient analysis (TTA) along the horizontal wellbore under a steam heating process. A novel concept of a heating ring is also introduced to measure the heat storage in the heated bitumen at the time of testing. Heating ring can be considered analogous to a drainage area in a conventional pressure transient analysis.

The proposed cooling time and formation thermal diffusivity calculated along the horizontal wellbore can be used to assess the effectiveness of the conduction heating. Cooling time in this paper is defined as the theoretical time required to cool the heated formation to the initial formation temperature. A longer cooling time indicates a higher net heat gain in the formation while the calculated thermal diffusivity is used to predict wellbore conditions and the type of fluid saturation along the horizontal wellbore. Thus, a combination of cooling time and formation thermal diffusivity can be employed to assess the effectiveness of heat injection during various steam heating processes.

By knowing the effectiveness of each heating scenario, the process can be selected and optimized not only to save heat energy and steam consumption but also to enhance bitumen recovery. This paper is limited to the new heating operation processes.
Well Performance Relationships in Heavy Foamy Oil Reservoirs
Authors: Kumar Rahul , Mahadevan Jagan
Published: October 2008

Inflow performance in some heavy oil reservoirs is not well understood as the fluid properties differ from conventional behavior. In this work, we develop an expression for inflow performance as a function of properties of foamy oils such as density, viscosity, solution gas-oil ratio and formation volume factor. We define two parameters, the end point entrained gas fraction and the apparent bubble point, adapted from previous studies, to account for the extent of entrained gas fraction in the liquid. The fluid properties are modified to account for the entrained gas and then incorporated in the equations describing flow from a reservoir at pseudo-steady state.

The results of our study show that the entrained gas and the apparent bubble point impacts the fluid properties and therefore the inflow performance at the bottom-hole conditions. In the presence of entrained gas, the density of the fluid decreases and the formation volume factor increases. Both these parameters show an inflection below the bubble point pressure and the solution gas oil ratio shows a constant value until the apparent bubble point is reached. The inflow performance curve, therefore, displays an inflection as opposed to the monotonically changing curve normally seen with conventional oils. The outflow performance curve is lowered when the effect of entrained gas is included and hence, the nodal systems analysis predicts a greater production rate for a foamy oil reservoir compared to a conventional reservoir.
Hot Rock Energy Projects-Australian Context
Authors: Goldstein B. A , Hill A. J. , Malavazos M. , Coda J. , Budd A. R. , Holgate F. L.
Published: October 2008

Hot rocks have potential to fuel competitive, emission free and renewable electricity for centuries to come. This potential is stimulating Hot Rock projects worldwide, calling upon integrated expertise from the petroleum, minerals and power industries.

Converting just 1% of the Australia's estimated crustal energy from depths between 150°C and 5 km (190 million PJ) to electricity would supply 26,000 years of Australia's 2005 primary power use, and that neither takes into account the renewable characteristics of hot rocks, nor resources below 5,000m.

Factors that distinguish Australian Hot Rock resources are:

Very radioactive granites are abundant, as in South Australia where the mean heat flow is 92µWm-2 compared to a global continental average of 51µWm-2. Areas of recent volcanic activity and hot aquifers above hot granites also constitute targets; and Australia is converging with Indonesia on a plate scale – giving rise to common, naturally occurring sub-horizontally fractured basement rocks that are susceptible to hydraulic fracture stimulation.

Most projects are focused on hot rocks to develop Enhanced (Engineered) Geothermal Systems (EGS) to fuel binary power plants. Roughly 80 percent of these projects are located in South Australia. Australian government grants have focused on reducing critical, sector-wide uncertainties and equate to roughly 25% of the cost of the private sector's field efforts to date. A national hot rock resource assessment and a road-map for the commercialisation of Australian hot rock plays will be published by the Australian Government in 2008.

Portfolio management methods can usefully be adapted to underpin decision-making by companies and governments seeking to respectively push and pull hot rock energy supplies into markets.

This paper describes the challenges and prospects for hot rock projects in Australia as a proxy for projects anywhere in the world.
Integrated 3D Geology Modeling Constrained by Facies and Horizontal Well Data for Block M of the Orinoco Heavy Oil Belt
Authors: Longxin Mu , Baojun Xu , Shancheng Zhang
Published: October 2008

It is very difficult to obtain the right variograms in the geostatistics to build an exact 3D geological model for the fluvial facies reservoir. This paper discusses how to calculate respectively the horizontal and vertical variograms based on the horizontal well data and vertical well data and then integrate with the 3D seismic data to get the reasonable variograms for the 3D geological modeling of the Block M. There are 95 horizontal wells and 21 vertical wells and the high resolution 3D seismic data of real amplitude and wide band reprocessed by the end of 2007 in the Block M of the Orinoco heavy oil belt. It especially emphasizes to do the sedimentary microfacies analysis and to use the sedimentary microfacies maps to constrain the sandbody distribution in the property modeling. These methods can clearly describe reservoir heterogeneities in geostatistical model and result in more accurate reservoir model.

Based on the high precision 3D geological model, the OOIP in the block is calculated. The 3D geological model has been successfully used to locate the horizontal well position and to direct the best orientation of horizontal wells in this Block.
Production – Log Base Model for Carbonate Permeability Distribution and Steam Flood Optimization
Authors: Ahamed Sayed Fadel , Choudhry M. A. , Abdulbaqi J. B.
Published: October 2008

Shallow shelf carbonate reservoirs like the Eocene heavy oil reservoirs of Kuwait-Saudi Arabian divided zone exhibit a high degree of fluid flow heterogeneity where carbonate admixture with anhydrite. Diagnosing shallow shelf carbonate fluid flow heterogeneity is a very complex problem and represents a big challenge. Moreover, assessment of vertical and lateral permeability variation is a key factor for success of any reservoir development plan. The Eocene heavy oil reservoirs are producing since 1956. limited old well core data, and absence of reliable transient pressure test has added challenges for assessing accurate permeability distribution.

This paper shows how the Eocene wells productivity could be correlated with the common available well logs to develop a log based-permeability model. A series of cross plots for the perforated intervals of highest and lowest productivity wells were constructed. These cross plots show a relationship between the well productivity and location of log parameters on the plots. Based on this observation a relation between rock quality or productivity and conventional log parameters was established. Regression analysis as well as neural net work was used to develop a relationship between permeability and log parameters. The technique was validated by comparison with new wells data; mobility from Modular dynamic tester (MDT), core data and wells productivity.

Based on the developed model, Eocene wells vertical permeability and interwell continuity can be used to optimize new well placement for the horizontal and vertical infill drilling. Also the developed model represents an effective tool to predict the steam injectivity profile and to understand the interesting anomaly related to temperature-depth distribution. Moreover, the developed model will be used to optimize Steam flood process and steam pattern well completion for improving efficiency of formation heating and delaying steam flood break through.
SAGD Gas Lift Completions and Optimization: A Field Case Study at Surmont
Authors: Handfield T. C. , Nations T. , Noonan S. G.
Published: October 2008

Gas lift completions for SAGD1 producers are unique. Conventional gas lift valves and mandrels with a packer completion cannot be used due to the extreme temperatures of the downhole environment. Most lift gas enters the production stream downhole via open-ended tubing or nozzles, which if not properly sized can result in operational issues, such as fluid / gas slugging and pressure instabilities which negatively impact the overall lift efficiency.

In 2006, ConocoPhillips conducted a study to design a gas lift system for the Surmont SAGD development that would allow better control of lift gas into the production string and in late 2007 the wells completed with gas lift were placed on production. This paper will cover the data collection effort and analysis completed to determine the efficiency of the two types of gas lift nozzles used in the completions, the methodology for optimization of SAGD gas lift systems and recommendations for future improvement.
An Integrated Approach to Permeability Modeling Using Micro-Models
Authors: Hosseini A. H. , Leuangthong O. , Deutsch C. V.
Published: October 2008

Spatial distribution of permeability is an important factor in the prediction of performance of Steam Assisted Gravity Drainage (SAGD) well pairs. Presence of short-scale variability in sand/shale sequences, preferential sampling of core data, and uncertainty in upscaling parameters are complications that make the inference of a reliable porosity – permeability relationship impossible. A simple yet effective way of overcoming these complications is micro-modeling. The central idea in micro-modeling is to use an additional source of information, namely digitized core images, to quantify the uncertainty in power-law averaging parameters and construct the porosity-permeability bivariate relationship by Monte Carlo Simulations (MCS). The work-flow in micro-modeling is comprised of a few steps from digitizing the selected core images to building 3D geo-blocks of binary sand/shale mixture, populating them with porosity/permeability values, upscaling the populated binary mixture by flow simulations, determining the uncertainty in power-law parameters and implementing MCS. The porosity-permeability relationships are constructed on a by-facies basis. Results of this research suggest that effective properties of clean sand are changing with the volume fraction of shale; and it has ultimately resulted in the development of an extended version of power-law formalism.
Examination of Oil Sands Projects: Gasification, CO2 Emissions and Supply Costs
Authors: Elliott Katherine
Published: October 2008

Global conventional oil and natural gas reserves are on the decline. As a result, non-conventional resource plays, such as Alberta's oil sands, are experiencing heightened global interest. Bitumen extraction and upgrading is an energy intensive process. This article focuses on gasification as a fuel alternative to natural gas for oil sands operation, reviewing current trends in oil sands reserves, energy requirements, the gasification technology and carbon dioxide (CO2) emissions. A supply cost methodology is employed to analyze the outlook of lower natural gas consumption and higher emission penalties for oil sands projects that integrate gasification.

The results of the supply cost analysis illustrate that an integrated oil sands extraction, upgrading and gasification project is less susceptible to operating cost pressures amidst rising natural gas prices due to its lower natural gas requirements. However, without means to mitigate CO2 emissions, the supply cost approach indicates that federal offset penalties of CAD 60 per tonne erode any benefit associated with the decreased natural gas use.
Practical Considerations of Reservoir Heterogeneities on SAGD Projects
Authors: Baker R. , Fong C. , Li T. , Bowes C. , Toews M.
Published: October 2008

SAGD has been implemented through a variety of different operating schemes. Determining the optimum and cost-effective strategy poses the greatest challenge to any SAGD reservoir. In addition to average rock quality, reservoir heterogeneities have a deep impact in steam chamber development and the overall volumetric sweep. This paper examines two well pairs in the Surmont pilot project. From this analysis and general experience, the following critical factors must be considered when optimizing SAGD operating strategies:

Getting enough heat close to the producer Accounting for areal (lateral) heterogeneity Identifying shale extent and its effect in partially retarding steam chamber height growth Determining the effect of water saturation and assumed irreducible water saturation Understanding that permeability is often higher than air permeability most likely due to dilation effects

This paper also addresses potential geological risk through analogy and the amount of heterogeneity that must be accounted for when developing a representative simulation.
Asphaltene Precipitation and Its Effects on the Vapour Extraction (VAPEX) Heavy Oil Recovery Process
Authors: Luo P. , Wang X. , Gu Y. , Zhang H. , Moghadam S.
Published: October 2008

Asphaltene precipitation is one of the most important physical phenomena during the solvent vapour extraction (VAPEX) heavy oil recovery process. After the asphaltene precipitation occurs, the produced heavy oil is in-situ deasphalted and thus has a lower viscosity and better quality. On the other hand, precipitated asphaltenes may plug some small pores of the reservoir formation and thus reduce its permeability. In this paper, a series of the VAPEX tests is conducted by using a rectangular visual sand-packed high-pressure physical model to study the detailed effects of solvent type, operating pressure, and sand-pack permeability on the asphaltene precipitation and subsequent deposition, which strongly affect heavy oil production and quality. It is found that when the operating pressure is close to the vapour pressure of pure propane or the dew-point pressure of a butane mixture, the occurrence and extent of asphaltene precipitation and deposition strongly depend on the sand-pack permeability. At a considerably high permeability of several hundred Darcies, asphaltene deposition occurs near the injector and solvent-diluted heavy oil drains quickly, which lead to a significant heavy oil viscosity reduction and a high oil production rate, respectively. When the sand-pack permeability is low and close to a typical heavy oil reservoir permeability, however, the residence time of the solvent-diluted heavy oil inside the physical model is long due to its low drainage velocity. A sufficiently high solvent concentration in the heavy oil causes severe asphaltene precipitation in this case. A large number of the precipitated asphaltenes are blocked and deposited at the pore throats so that the porous medium is plugged to some extent.
The Slender Bubble Model for Very Slow Degassing in Porous Media and Cold Production
Authors: Chraibi Mehdi , Zaleski Stéphane , Franco Fabienne
Published: October 2008

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.
The Influence of Diffusion and Dispersion on Heavy Oil Recovery by VAPEX
Authors: Alkindi Abdullah , Muggeridge Ann , Al-Wahaibi Yahya
Published: October 2008

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.
A New Water Treatment Scheme for Thermal Development: The SIBE Process
Authors: Pedenaud Pierre , Dang Fabrice
Published: October 2008

The production of extra heavy oil or bitumen through Thermal methods (e.g. SAGD - Steam Assisted Gravity Drainage) requires the generation and injection into the reservoir of significant quantities of steam which is finally recirculed with the produced bitumen. Considering the need to minimize fresh water consumption and the possibility of increasingly stringent environmental regulations, it is likely that maximization of the recycling of the produced water into steam will be mandatory.

The SAGD water treatment scheme is complex because it depends on the water characteristics, the steam generator type selected (OTSG or conventional boiler) and the decision to completely eliminate waste water disposal (zero liquid reject) or use other waste handling and disposal methods. SAGD water treatment also faces some additional specific challenges compared with oil fields worldwide, such as the high silica content in the produced water.

An overview of the current water treatment process options for SAGD will be presented, followed by a new patented process called SIBE (ie Silica Inhibition and Blowdown Evaporation). The principle of this new process is based on TOTAL's research in the area of silica inhibition and an optimized application of conventional water treatment equipment with Zero Liquid Discharge process (e.g. evaporators and Crystalliazer). An estimate of the economic benefit of the new SIBE process relative to conventional process schemes will be presented.
Methodology of Calibration for Nucleonic Multiphase Meter Technology for SAGD Extra Heavy Oil
Authors: Pinguet Bruno , Pechard Philippe , Guerra Elsie , Arendo Vincent , Shaffer Mark , Contreras Jose
Published: October 2008

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.
Combined Reservoir Simulation and Seismic Technology, A New Approach for Modeling CHOPS
Authors: Aghabarati Hossein , Dumitrescu Carmen , Lines Larry , Settari Antonin
Published: October 2008

Cold Heavy Oil Production with Sand (CHOPS) has become one of the main recovery schemes for developing heavy oil reservoirs in Canada. This became possible with the introduction of progressive cavity pumps, therefore much higher sand cut in viscous heavy oil could be expected from unconsolidated/weakly consolidated formations as opposed to conventional pumps with limited capacity.

In this study, combined reservoir simulation and seismic technology are applied for a heavy oil reservoir situated in Saskatchewan, Canada, for better understanding of the reservoir properties and recovery mechanism. The numerical model was built based on the well log data and several seismic attributes. The integration of seismic attributes improved modeling reservoir heterogeneity, which is a main challenge in modeling sand production.

Firstly, we used geostatistical methods to estimate the initial reservoir porosity, using a seismic survey acquired in 1989. Secondly, sand production was modeled using erosional velocity approach and the model was run based on the oil production. Finally, results of the true porosity derived from simulation were compared against the porosity estimated from the second seismic survey acquired in 2001. This flow provides new tools that validate the simulation model results against the seismic data.

Following this approach the extent and the shape of the enhanced permeability region (wormhole region) for estimated porosity distribution are modeled. The performance of the CHOPS wells is highly dependent on the rate of creation of the high permeability zone around the wells. This method can be used for evaluating future developments of the field such as infill drilling and post CHOPS recovery methods (VAPEX).
The Integrated CO2 Pilot in the SW of France (Oxycombustion and Geological Storage): A Potential Answer to CO2 Mitigation in Bitumen Production
Authors: Aimard Nicolas , Prébendé Claude , Cieutat Denis , Tsiava Rémi
Published: October 2008

In Alberta, Oil & Gas operators are developping Extra Heavy Oils (EHO) production fields requiring much more processes and energy than conventional oil. Consequently, the associated GHG emissions could be potentially huge and operators are seeking options to reduce them. Among the possible options, Carbon Capture and geological Storage (CCS) appears to be the most promising option in addition to power efficiency increase and use of renewable or alternatives energies.

For EHO thermal production, a huge quantity of steam is required; therefore a large quantity of CO2 per produced barrel could be emitted. The existing and future boilers will have to capture these emissions efficiently, either with post-combustion like amine unit, or oxycombustion. New boilers have to be designed to integrate the most appropriate "capture ready" solutions.

TOTAL launched at the end of 2006 an integrated CCS project at Lacq, in the South-West of France. It entails the conversion of a steam boiler into an oxy-fuel combustion unit. The pilot plant, which will produce some 40 t/h of steam, will emit up to 120,000 tons of CO2 over a 2-year period. The CO2 rich flue gas will be cleaned up and compressed. The resulting CO2 will be conveyed via pipeline to a depleted gas field, 30 kilometers away, where it will be injected into a deep carbonate reservoir. CO2 injection start-up is scheduled beginning 2009.

This paper demonstrates that oxycombustion could have some adavantages compared to post-combustion for CO2 capture in term of energy efficiency for steam generation. Secondly, it presents the characteristics of the 30MWth oxy-gas boiler, one of the first world industrial oxy-combustion units. Then, it focuses on the new equipment to retrofit the drum boiler to oxy-combustion: the Air Separation Unit, the Oxy-combustion System developed by Air Liquide, the Flue Gas Recycle set up, the CO2 cooling, compression and drying before transportation.
Enhanced Heavy Oil Recovery on Depleted Long Core System by CH4 and CO2
Authors: Shi R. , Kantzas A.
Published: October 2008

This paper describes a laboratory study of potential post-cold production strategies for heavy oil reservoirs. The tests were conducted on two primarily depleted long core systems (glassbeads core and sandpack core). The glassbeads core is 18.2 m in length with higher permeability (11.8 Darcy) and the sandpack core is 18.5 m long with lower permeability (1.9 Darcy). Both core systems were recharged by CH4 injection followed by a depletion step similar to the cold production experiment. Both cores were then exposed to a single cycle of CO2 injection, soaking and production. This work aims at further understanding the heavy oil solution gas drive mechanism. Furthermore, the study aims at assessing methane and carbon dioxide recharging as a potential recovery method for heavy oil reservoirs, and at establishing a base line for comparison against each other. Results of this study indicate that CH4 and CO2 recharge processes give an additional 8% and 9% OOIP recovery for the glassbeads core and the sandpack core, respectively. Since the cold production for the glassbeads core (22.2% OOIP) was high, the low recharge recoveries may be pessimistic. However, for the sandpack core, the recharge recovery appears more optimistic with almost similar recovery to that of cold production (about 10.2% OOIP).