bluuebunny/crossref_metadata_2025 huggingface dataset:
Steam and Glean: Planning to Learn in a Potential World-Class Heavy Oil Project
Authors: Bynum C. W. , Weller M. F. , McManus C. D. , Haskett W. J.
Published: February 2011

As the first hydrocarbon development in Madagascar, the Tsimiroro field is an onshore heavy oil asset (mean resource nearing 3.5 billion barrels @14°API) located inland from the western coast covering approximately 900 square kilometers. The project is in early assessment and resource identification phase nearing steam flood pilot implementation. Adequate interpretation and treatment of existing subsurface data is crucial to determining the optimal path to maximum field value. Beyond resource, there are substantial variables related to above-ground risk and operational decisions including processing, transportation, and marketing. While important for any project, these aspects become critical for this, the first commercial project in a non-oil producing country with minimal infrastructure.

Subsurface and operational risks, as well as strategic project objectives/decisions were approached using industry leading probabilistic methods, capable of testing pathways through highly complex situations. The evaluation included an integrated approach to deal with the full value-chain of the steam flood project. This process, rooted in statistics and decision theory, helps determine significant value drivers and illuminates uncertainty reduction opportunities. It identifies and prioritizes risk mitigation measures leading to a better expected asset value.

A pilot program was re-designed to focus on critical learnings and will help de-risk many of the important project variables at a relatively low cost - an insight which could not be gleaned from a traditional deterministic analysis. A probabilistic evaluation of the resources in place indicated that further delineation of the field via drilling and Electrical Resistance Tomography would resolve significant subsurface uncertainty. Further, investigation of export transportation methods, alternatives for oil upgrade, and commercial alternatives for oil disposition were evaluated in detail to reveal which options were viable to pursue, and which had low priority for further investigation.
Experimental Measurement of Diffusion Coefficient of CO2 in Heavy Oil Using X-Ray Computed-Assisted Tomography Under Reservoir Conditions
Authors: Song L. , Kantzas A. , Bryan J.
Published: February 2011

Injection of carbon dioxide has shown process and economical advantages for enhancing the heavy oil and bitumen recovery by reducing viscosity under the reservoir conditions. Mass transfer is the first mechanism to occur when carbon dioxide is injected into the reservoir. Consequently, the measurement and evaluation of the diffusion coefficient is essential to develop feasible and economic technology for extraction of heavy oil and bitumen. However, not much effort has been put into the experiments of carbon dioxide and heavy oil for understanding and calculation of the gas-liquid diffusion coefficient. The purpose of this study is to evaluate the feasibility of determining experimental diffusion coefficients of carbon dioxide in heavy oil by employing X-ray Computed Assisted Tomography (CAT) and a non-iterative finite volume method, and investigate the impact of different experimental conditions on diffusion coefficients.

The results indicated that the measured carbon dioxide diffusion coefficients are consistent with those reported in the literature for similar gas-heavy oil systems. X-ray Computed Assisted Tomography (CAT) and a non-iterative finite volume method were successfully applied to study the diffusivity of carbon dioxide in heavy oil. In addition, the concentration and diffusion coefficients of carbon dioxide in heavy oil depend on diffusion distance as well as on diffusion time and pressure.
An Analytical Model to Predict Cumulative Steam Oil Ratio (CSOR) in Thermal Recovery SAGD Process
Authors: Miura Kohei , Wang Jin
Published: February 2011

This paper presents a simple yet sophisticated analytical model to predict cumulative steam oil ratio (CSOR) using the material/energy balance and gravity drainage theory, in which CSOR is a function of average reservoir properties (porosity, permeability, heat capacity, and thermal conductivity), and time-dependent variables (injection temperature, rising chamber height, chamber oil saturation, and producing fluid temperature) to mimic the practical SAGD process. This model has been applied to predict CSORs of the typical wells in the JACOS’ Hangingstone SAGD project. History match results show the reliability and accuracy of the model at different geological conditions. The analytical model has proven to be satisfactory to predict CSOR by reasonably adjusting a few reservoir parameters, such as formation permeability, effective net pay, and operational parameters.
From CSG to LNG: Modeling and Understanding Key Subsurface Uncertainties for the Development of a Surat Basin Opportunity, in Queensland, Australia
Authors: Lagendijk E. , Ryan D.
Published: February 2011

Arrow Energy intends to develop its certified coal seam gas reserves in the Surat Basin to supply gas to a proposed liquefied natural gas (LNG) plant located in Gladstone, Queensland. The large scale development of the Surat Basin for the LNG Project required basin-wide geological modeling. The Surat Basin coal structure and properties were reviewed in detail and modeled to estimate Gas Initially in Place. Dynamic simulation was subsequently performed to estimate total recoverable volume and generate a robust development plan for the LNG Project.

Key subsurface risks consist of access to sufficient gas volumes within the area of interest and gas deliverability to meet and maintain gas supply to the LNG Project. To minimise the likelihood, and to reduce the consequences of these risks, subsurface uncertainties were identified and low and high values for each uncertainty were assessed with the aim to understand impacts on the LNG Project.

Gas content, permeability and Net to Gross resulted in the biggest impact on the LNG Project, followed by relative permeability curves, coal heterogeneity, isotherms, permeability variation with pressure, coal compressibility and potential aquifer connection. Other uncertainties, including coal depth cut-off, sorption time and initial reservoir pressure had a lower impact on the number of wells required for the LNG Project.

Subsurface sensitivity analysis combined with probabilistics was used to generate 90%, 50% and 10% probability subsurface models. These were carried forward for development planning to generate a range of development outcomes and production forecasts for economic evaluation to ensure a robust LNG field development plan.

This paper describes the integrated reservoir data analysis and dynamic modeling methodology for the purpose of the large-scale development of this Surat Basin opportunity and outlines how key uncertainties were identified and addressed.
An Innovative Cementing Solution for the Grosmont Carbonate
Authors: Arseniuk S. E.
Published: February 2011

Alberta's oil sands contain an estimated 286 billion m3 (1.8 trillion barrels) of bitumen, including more than 64.5 billion m3 (406 billion barrels) in the Grosmont Carbonate. The Grosmont at Saleski represents a significant resource, which will be developed from pilot to commercial development. The operating company plans to recover bitumen from the Grosmont using solvent-cyclic, steam-assisted gravity drainage (SC-SAGD), beginning with a pilot in the Saleski field.

The Grosmont has been noted for drilling challenges relating to lost circulation, including difficulty in cement placement. To address these challenges, lightweight, foamed, thermal cement was specifically engineered, tested, and qualified for use at the pilot. This blend addresses placement challenges and was designed to achieve the mechanical properties required for zonal isolation and well integrity throughout the life of the well.

This paper discusses the design and development of the blend using finite-element analysis (FEA) software to evaluate blend suitability, laboratory testing results to confirm basic properties, installation in the pilot wells, and results using ultrasonic cement-inspection tools.
Modeling Well Performance Data From Overpressured Shale Gas Reservoirs
Authors: Thompson J. M. , Nobakht M. , Anderson D. M.
Published: February 2011

It is widely known that shale gas wells require hydraulic fracturing to generate greater wellbore contact with the reservoir in order to achieve economic gas rates. When this type of completion is applied to ultra-tight rock, long-term linear flow is expected and has been widely confirmed through analysis of production data. However, in some shale gas production data, such as the Haynesville, we have observed a markedly different behavior, characterized by the appearance of apparent boundary dominated flow early in the production life of the well. Furthermore, we have observed major inconsistencies between drawdown and buildup data in some of these wells, which is a reliable indicator of degradation in well productivity through time. Although the nature of the productivity loss (kh, skin, fracture conductivity, etc) is usually indeterminable from well performance analysis, its magnitude is clearly evident in well production histories that contain intermittent shut-in periods with measured buildup pressures.

In overpressured reservoirs containing fractures (such as the Haynesville), the reduction of pore pressure resulting from well production through time will sometimes cause the fractures to close, thereby decreasing fracture conductivity. This process, while expected, has not been experimentally verified for the Haynesville (at least within the public literature). We believe that the concept of pressure dependent fracture conductivity (which can be modeled as effective permeability) is a suitable explanation of our observations of well performance data in the Haynesville.

In this paper, we use simulated data to illustrate that the presence of pressure dependent permeability causes a clearly identifiable signature in production history data containing intermittent buildups. In addition, we will show that in the absence of buildup data, analysis of well performance will significantly under-predict original-gas-in-place (OGIP) and expected-ultimate-recovery (EUR) in reservoirs with pressure dependent permeability. Finally, we will show that operating conditions (changing or constant flowing pressure) may have a huge impact on the interpretation of production data, particularly (but not exclusively) in the presence of pressure dependent permeability.
A Study of High-Quality Foamed Fracturing Fluid Properties
Authors: Wheeler Richard S.
Published: February 2011

In recent years successful stimulation and extraction of hydrocarbons from unconventional reservoirs has led to various approaches to the stimulation process. Slickwater stimulations pumped at very high flow rates have become the staple in formations such as the Barnett Shale. High treatment rates are made possible by the implementation of low dosages of polyacrylamide, which lower the effective pipe friction. This type of treatment process is common among other shale and tight gas plays throughout North America. Other types of treatments include conventional crosslinked or linear gelled fluids. Some treatments combine the conventional crosslinked fluids and the slickwater approach. Experimentation with multiple stimulation programs is a response to the changes in formation properties that vary from one formation to the next and within areas of the same formation. Over the last few years there have been several successful treatments implementing a high-quality foam stimulation in some shale formations. These treatments have usually included a gas phase in excess of 90 quality and often as high as 99 quality. This type of treatment is especially fitting for low-pressure reservoirs and in depleted zones. One advantage of a high-quality foam is its reduced environmental impact by using very small quantities of water as compared to high-rate slickwater stimulations. In these particular high-quality foams, a viscoelastic surfactant gel is used in the liquid phase as the gelling and foaming agent. With the combination of high-quality foam and non-damaging viscoelastic gel, the total fluid is completely non-damaging to the formation. Successful treatments in formations in the northeastern United States have led to a demand for use in other formations, necessitating a better understanding of fluid properties in order to design treatments. Very little published data is available for high-quality foam fluid properties. A study has been conducted to examine the fluid characteristics of high-quality foams as compared to typical 50 - 70 quality foams. This study will show trends of viscosity, foam stability and temperature sensitivity of high-quality foams using xanthan, guar-based gelling agents and viscoelastic base fluids.
Well Log Cluster Analysis: An Innovative Tool for Unconventional Exploration
Authors: Euzen T. , Delamaide E. , Feuchtwanger T. , Kingsmith K. D.
Published: February 2011

Well Log Cluster Analysis: an Innovative Tool for Unconventional Exploration Tristan Euzen, Eric Delamaide, Tom Feuchtwanger, Kim Kingsmith.

Exploring for economically viable accumulations of hydrocarbons, the task of explorationists is becoming considerably more complex in mature basins because of the unconventional nature of most remaining resources. Analyzing a large volume of data is required in order to develop a comprehensive understanding of reservoir distributions and/or their production performance characteristics. Furthermore, the unconventional nature of reservoirs makes it challenging to interpret well log data and indentify potential gas pay using conventional data analysis approaches.

Well log cluster analysis is an innovative approach that provides the explorationist with an efficient tool for analyzing, screening and filtering a large volume of well log data, in order to identify and map potential hydrocarbon accumulations. The method involves seeking high density areas (clusters) in the multivariate space of well log data, in order to define classes of similar log responses. These classes called electrofacies can be calibrated using various sources of data such as core description or production data and can then be used to process very quickly hundreds of wells.

Cluster analysis and electrofacies classification have been applied to develop unconventional gas prospects in the Upper Mannville incised valley fills of the WCSB. The reservoirs dominantly consist of arkoses with complex mineralogy, and are characterized by both conventional and unconventional production from low resistivity pays. A cluster analysis was first performed on 5 producing wells used as training samples, and an electrofacies classification was then performed on 395 wells in an area of 28 townships. A quality control of the results was done by checking the electrofacies interpretation in front of producing intervals from 41 wells. The preliminary results are very promising, with 89% of the producing intervals used in the blind test properly predicted by the electrofacies classification. Finally, potential gas bearing intervals identified by the electrofacies classification have been mapped in order to define prospective areas. This approach has many potential applications in the field of unconventional hydrocarbons, especially where conventional log analysis doesn't work properly and where a large volume of well log data is available.
Enhancements to Remotely Operated Downhole Fluid- Loss Isolation Barrier Valves Enable Reliable Operation in Debris-Laden Conditions
Authors: Robb Graham , Robb Ewan , Inglis Peter
Published: February 2011

With the increasing demand for technology to perform in more extreme operating conditions, service companies continue to seek solutions that will enable operators to meet the increasing demands more efficiently.

This paper will focus on remotely activated Fluid Loss Isolation Barrier Valves (FLIBVs) that are used to retain wellbore fluids during completion/workover operations to prevent formation damage and improve the well productivity index. One of the current innovations for deep water is a remotely activated FLIBV. Remote activation offers significant benefits to the operator when compared to conventional fluid-loss devices; i.e., the operator can save days of rig time, as there is no need for well intervention to open or remove fluid-loss devices to bring the well into production.

Several designs have been deployed globally over the last few years, however, this paper will focus on one design that provided a remote-opening success rate of 94% in over 140 installations. The valves that did not open remotely were usually those that had been suspended with the ball closed in extremely debris-laden conditions. While the 94% success rate is certainly exceptional, the engineers that designed the equipment felt that the issues that were causing the valve failures should be addressed. When the failures were reviewed, it was determined that the problems concerned suspension in debris-laden conditions. The engineers subsequently made changes that would allow successful performance in the environments in which the original design had failed, and in the cases in which the new design was deployed, 100% remote opening success in over 20 installations to date was achieved. This paper discusses the improvements that were made to address: The opening of the remotely-activated FLIBV in debris-laden conditionsThe testing conducted to prove that the changes would provide a more reliable product that could operate after being suspended in the debris-laden conditions.

Case history data will be presented to illustrate the success of the enhanced remotely opened fluid-loss device.
Lower Completion Type Comparisons: Longhorn Deepwater Case Histories
Authors: Sanford J.R.. R. , Flanagan E.J.. J. , Mancini C.. , Bruton J.. , Woomer J.D.. D. , Franklin B.. , Hebert L..
Published: February 2011

Selecting a lower completion method is often difficult to evaluate because the true time/cost savings is unknown. This is usually due to the lack of an “apples to apples” comparison. Five (5) wells and four (4) different lower completion types were performed in the Longhorn development (All were performed in the same pressure/temperature regime, similar depths and utilized the same rig). This paper will review the lower completion case histories of this development. The completion types included a conventional single (2 trips), a 1 trip system, a conventional stacked pack (2 zones) and a multizone single trip system (2 zones).

This paper will review, compare and document four (4) different lower completion types. Application of the results should help every completion engineer; answer the question “What lower completion method should I use?” The following time savings, normalized with no non-productive time, were as follows: ❖One trip savings was 1½ days less than a conventional single (2 trips).❖Multizone Single Trip Systems (MST1) (two zone) was only 0.5 day longer than a conventional single (1 zone) which is equivalent to the second zone pumping time.❖MST time savings was four (4) days less than a conventional stacked pack (two zones).

Choosing the correct completion technique is the primary objective of every completion engineer. Understanding the risks and costs associated with each completion type is essential in performing this task.
Leveraging Innovative Technologies to Recover Reserves in the Bakken Formation
Authors: Lloyd W. B. , Starkey A. A. , Jany J. D.
Published: February 2011

The Bakken formation in the Williston Basin has received increasing recognition over the past five years due to the ability of operators to consistently deliver wells with prolific production results and extraordinary economics. This has been made possible by the steady advancement of technologies associated with drilling and completing horizontal wells in addition to the majority of the wells being located in the core of the formation where reservoir pressure gradients are at their maximum.

The magnitude of the Bakken formation means that the majority of the acreage is considered intermediate or outlying from the core presenting the challenge of making the normal pressured reservoir in these areas economically viable. This paper presents a unique combination of drilling optimization with advanced open hole, multi-stage fracturing system (OHMS) technology, which together are pushing the envelope for continued improvement in operational and production efficiencies.

This paper will present directional drilling advantages and artificial lift benefits using rotary steerable technology and advancements in OHMS allowing increased stage density for production optimization. Through the proper implementation of these leveraging technologies, the time to drill and complete a well in the Bakken has been reduced and fracture stage density has been increased over current standards igniting a continuing trend to increase stage density in the Bakken formation as a result of significant gains in sustained recovery.

This systematic approach to streamlining the drilling and completion programs has resulted in notable improvements in the economic metrics for the play. The technological progress presented has resulted in a dramatic shift in the industry in terms of drilling and completion in the Bakken formation and the techniques described can be adapted and applied in virtually any resource play.
Application of Inorganic Whole Rock Geochemistry to Shale Resource Plays
Authors: Wright A. M. , Spain D. , Ratcliffe T. K.
Published: February 2011

In recent years shale resource plays have become increasingly important. However, understanding the controls on reservoir quality in shale formations is still in its infancy, despite thousands of well penetrations. Using examples from several shale resource plays, including the Haynesville, the Eagle Ford and the Muskwa formations, this paper demonstrates how inorganic whole rock geochemical data that are primarily obtained to provide stratigraphic correlations can be used to model mineralogy, model TOC, determine paleoredox facies, recognize zones of biogenic silica and aid with sequence stratigraphic interpretations.

The primary application of whole rock geochemical data to date has been providing stratigraphic correlation based around changes through time in elemental composition, i.e. chemostratigraphy. Stratigraphic correlation is of paramount importance for temporally and geographically constraining other reservoir characteristics. In addition to classic chemostratigraphy, the whole rock geochemical data provide information about terrigenous inputs, which can be used to help elucidate transgressive – regressive cycles and thereby help with understanding sequence stratigraphic correlations.

Reservoir quality in shale is dependent largely on mineralogy. Major element concentrations determined for chemostratigraphy can be used to model most mineral phases, including quartz, clay (semi quantitative abundance of kaolinite, illite and chlorite), calcite, dolomite, feldspars, pyrite and apatite. By adding select trace elements, typically U and Ni, the TOC contents can also be modeled. Furthermore, it will be demonstrated how by combing SiO2 concentrations with elements derived from terrigenous sources, it is possible to recognize zones where biogenic silica is present.

Paleoredox plays an important role in determining TOC values. Consideration of redox-sensitive elements, such as V, Ni, Th, U and Mo provides a means to determine the degree of anoxia during deposition. Using examples from the Haynesville Shale, it will be shown how anoxia is determined and how it varies laterally within the basin.

The methodologies shown in this paper are readily exportable to any shale resource play. The results can be generated from core, side-wall core and cuttings samples, providing a rapid, cost effective means to assess shale in a well-bore penetration.
Coping With Surface and Downhole Interference on Tightly Spaced Completions Pads in the Horn River
Authors: DeMong Karl , Fahlman Jeff , Schnell Rod
Published: February 2011

In gas shales the completion process can be described as changing the source rock into productive reservoir rock with the application of a fracture treatment. Successful shale gas operators have been applying technology to shift to drilling fewer wells and getting better coverage of the rock volume with fracture treatments. Overall this approach gets better results with fewer resources than the historic approaches used on tight gas plays. This tactic, however, has led to significant changes in the way work is done in the field. Now operators are consolidating operations from numerous sites into a few larger pads with many wells drilled from the same surface location. This environmentally sensitive approach has yielded far less surface disturbance but created some other consequences as well. The resulting close surface and subsurface well proximity has resulted in new safety, technical and operational challenges. A large part of the completions engineering effort is focused on solving both surface and subsurface issues related to proximity. Apache has recently completed a pad of 16 wells with 274 completed intervals in the Horn River area.

In this paper both surface and subsurface interference issues will be discussed as well as the plans for coping with the interference. Examples of interference situations and recorded downhole pressure communication from the project will be discussed with a focus on how new processes and automated tools such as the newly developed surface safety protocols and a subsurface proximity calculator enhances the planning of operations and the safety of the site.

Apache has developed a subsurface completions proximity calculator to enhance the ability to plan and adjust downhole operations in an environment that may change day to day or hour to hour. The tool collects all the subsurface data and instantly gives a picture of downhole interactions and supports planning to reduce risk. The avoidance of exposure of high pressure operations to other critical lower pressure operations, such as fraccing proximate to drilling or completion interventions, will be outlined.
Economic Assessment of HSE Risk Management and Raising Efficiency of Financial Resources
Authors: Merzlyakova Ekaterina
Published: February 2011

In modern world the well acknowledged tool for management in industrial and environmental safety, and occupational health are the management systems conforming to ISO 14001 "Environmental Management System" and OHSAS 18001 "Occupational Health and Safety Management Systems" International Standards.

Amid the increasing competitive ability and global financial crisis, it is very important to be able to assess the efficiency of investments in HSE activities aimed at mitigation of Company’s negative impact upon the environment and personnel.

When developing such a system of economic assessment, the author has analyzed different methods applied for environmental performance assessment and has studied thoroughly the requirements of ISO 14031 "Environmental Performance Evaluation" International Standard.

Based on mathematical and statistical methods, the author has elaborated an HSE performance evaluation system which enables to assess efficiency of HSE activities performed in the company. This evaluation system assumes differentiated approach to assessing all kinds of negative impact on the environment and the personnel of the company with application of input and output cost indicators. In compliance with ISO 14001:2004 and OHSAS 18001:2007 two kinds of impact on the environment and the personnel have been sorted out in Udmurtneft - environmental aspect and hazard to the personnel, correspondingly.

The research paper contains the detailed calculation of efficiency of financial investments in the personnel hazard management "Feral-herd infections" in N company. This hazard is a top priority risk in the company since such infections are located in the region.

High efficiency of the personnel infection risk mitigation activities was proved on the basis of mathematical method and risk mitigation results were demonstrated by the model risk matrix.

Thus the developed HSE performance evaluation system enables to assess the effectiveness of HSE Integrated Management System on the whole and to allocate the financing wisely and implement risk management activities in the most successful way.

Objectives of the research paper: –development of the HSE Integrated Management System efficiency evaluation system which would allow fulfilling several tasks:–optimization of planning the activities and financing;–providing visuality of HSE activity planning and assessment for the management team;–improvement of HSE management system;–providing transparency of HSE activity in the company.
Designing of Complex Information and Control System of the Deposit "Urubcheno-Tohomskoe"
Authors: Zebzeev Alexey
Published: February 2011

The practical use of modern information technologies is an effective way of increasing the operating efficiency of oil-and-gas, which enables to update business processes at all levels of management, production and sale activities. One of the tools to achieve these goals is the complex management information system (CMIS) starting from the local automation equipment of each processing facility and right up to the the automated integration and data processing system (AIDPS) of the company. The application of complex management information systems provides ample opportunities for the mobilization of reserves meant for the reduction in manufacturing and non-manufacturing costs and losses and also at the increase of income of oil- and-gas companies. To implement the necessary functions in Yurubcheno-Tokhomskoe field, the facilities of automated process control systems (APCS) are supplied with certain amounts of automation. To solve the functional tasks, the specialpurpose software tools are used as capable of operation with real time data. Construction of the CMIS system in compliance with the assigned requirements provides the collection of production information to the necessary extent, storage, processing and representation of the information, completion of the applied tasks which contribute to complex engineering evaluations and modeling of production processes and facilities. While designing the CMIS of Yurubcheno-Tokhomskoe field, the controlled facilities were combined on the technological basis as facilities of oil production and reservoir pressure maintenance, oil treatment and transportation, life support and power engineering. In the CMIS structure the second level of APCS is implemented for operational dispatcher control over the production. The AIDPS accumulates information from lower levels of the automation in real time and converts them into meaningful production events for the further analysis. The basic performance indicators of an enterprise, which are positively influenced by the CMIS application mainly include the increase of efficiency and reduction in production costs. Decrease in cost of production refers to all types of costs: raw materials, energy carriers, human resources, etc., and it is conditioned by an accurate production planning which enables to optimize the use of all the enterprise resources. Increase in efficiency is mainly resulted from improvement of workflow, in particular the planning process, paperless production management, more effective preparation of accounts, elimination of doubling during data access, etc. The CMIS application also provides increase in the enterprise prestige and improvement in the quality of production, emergency situation prevention, production and environmental safety.
Technical and Economic Strategy in the Scale Deposition Management is an Important Factor in Enhancement the Efficiency of Oil Production
Authors: Voloshin Alexander , Ragulin Viktor , Neviadovskyi Evgenii , Ganiev Ilgiz
Published: February 2011

The deposition of inorganic substances that accumulate in the Electric Submersible Pumps (ESP′s), tubing, and piping systems, equipment for the collection of oil is a significant complicating factor in oil production. The practical results of scale management was shows that the cost of prevention scale deposition is ten times less than the financial cost to remedy the effects of scaling.

This paper presents the main provisions of the technical and economic management strategy scaling in the West Siberian oil fields Rosneft, are the criteria for selecting technologies to prevent scaling, implemented in the form of matrices and patterns, as applicable, developed an integrated approach based on the identification of “bottlenecks” in the full cycle of oil production: from the producing formation to the processes of the oil. Depending on the degree of salt saturation of formation water, oil sold technology, offers a range of technologies to combat scaling - from simple, traditional methods of protection to more complex integrated treatments. It is shown that the implementation of such an approach leads to a significant reduction in costs due to the problem of scaling.
Mayskoe Oil Field Tymen Suite Tight Sands Reservoirs Development Strategies
Authors: Naymushin D. , Popov A. , Klimov A. , Martynov A.
Published: February 2011

Resume

So called “classic” type reserve (reserves are developing by traditional ways - by using regular waterflooding patterns and without huge quality of reservoir stimulation or enhance oil recovery actions) depletion throw down a challenge to oil production companies including in production “tight reservoirs”. “Tight reservoirs” is the term commonly used to refer to reservoirs contents in heterogeneous of permeability deposit (with alternation of it), are contented water in cross section, with gas cap etc., and however, liberal share of it is a low permeability reservoir. This type of reservoirs recovery require from oil production companies apply additional, often not standard and as a rule expensive decisions for achievement profit oil recovery factor. In this article review so type reservoirs development strategies is made by the example of Mayskoe oil field (Tomsk region). For Imperial Energy Company this task is very actual because half of all reserves in Company are tight reservoirs with permeability near 1 mD, this factor explains interest of it in developing this type of reserves.
Bottom-Hole Formation Zone Treatment using Monofuel Thermolysis
Authors: Graifer V. , Kokorev V. , Orlov G. , Bugayev K.
Published: February 2011

The paper sets forth some major aspects of the bottom-hole formation zone treatment with the use of monofuel thermolysis.

The bottom-hole formation zone treatment using monofuel (MF) thermolysis refers to thermal and gas chemical enhanced oil recovery. It is an effective combination of heat and chemical monofuel combustion products; their integrated effect results in the following: –improvement of lithological bottom-hole formation properties as a result of heat treatment and creation of pressure impulse attributing to the removal of asphaltic tar paraffin depositions (ATPD) and fracture formation.–oil viscosity decrease resulted from heat effect and monofuel thermolysis products;–lowering of surface tension at the interface of displaced and displacing fluids and improvement of rock surface wettability.—decomposition of chemical agents under the temperature effect producing gases and other substances which increase displacement efficiency;—formation of water-, gas-and-oil emulsions and foam systems in highly permeable zones resulting in leveling the displacement front and increasing involvement of heterogenous formations into the oil recovery process.

Principally MF represents the solution of combustion agents and oxidants according to the general pattern: “oxidant + combustion agent + solvent”.

The MF advantage is the following: it requires no solution related to propotional dosage and allows control of heat and gas effects by simple methods. In addition it considerably increases allowables for oil formation depths to be treated due to the possible injection of liquid monofuel by high pressure pumps. The injection pattern is single flow. It reduces accessories, and the number and range of the equipment used.

As a monofuel the technology uses water solution of cosoluted nitrogen containing compounds, one of which if fuel, the other - oxidant.

MF decomposition in the fluid is a number of redox reactions yielding the following end products: Water H2O-steam, nitrogen N2, carbon dioxide CO2 and ammonia NH3.

Water is the solvent and reaction product. It changes to steam in the process temperature conditions. The change consumes some energy produced in MF thermal decomposition and oxidation.
Multiphase Flow Measurements: Vankor Experience
Authors: Semenov A.A. , Bakhitov R.R. , Abramochkin S. A.
Published: February 2011

Provision for oil, gas, and water surface rate measurements from every production well is one of the most required issues for effective field development control. Several types of multiphase rate measurement units are available with various principle of measurement of the total producing liquid rate and the volume cuts for gas and water. Due to oil degassing during production, gas and water breakthroughs, and subsequently high liquid rates (up to 1600 m3/day), this task has become absolutely non-trivial for the Vankor wells.

Preliminary, cyclone-based gas-separators have been considered in the field as the means for primary phase separation and consequent measurement of the each phase rate using Coriolis-based mass metering units. However, due to the narrow operating range of both the cyclone separators and Coriolis mass-metering units, correct rate measurements were failed to achieve and such obstacle was confirmed by multiple comparison measurements with a stock tank.

A mobile measurement unit with Venturi tube and using electrical principle for measuring gas and watercut has been used in the field. Due to the necessity for calibration to reference rate measurement units, use of extensive input PVT properties, and diverse relationship between electrical properties of the gas-liquid fluid and volume fractions for gas and water, the use of this unit could not help in increasing the accuracy of liquid rate measurements over 15% and covering the full production range of wells.

Another unit type for multiphase flow rate measurements uses Venturi tube and radioactive source for gas and watercut. The introduction of the unit at the field allowed one to increase the accuracy of liquid rate (within 5% for several wells), gas-oil ratio, and watercut measurements significantly. It delivered an opportunity to increase a material balance model and carrying out a full-scale dynamic model history matching of the Vankor field.
Coalbed Methane Artificial Lift Challenges from Alberta's Mannville Coal
Authors: Johnson B. A.
Published: February 2011

In developing the Doris Mannville Coal Bed Methane (CBM) gas field near Fort Assiniboine, Alberta, the Nexen exploitation team encountered many unforeseen artificial lift challenges using Electric Submersible Pumps (ESPs). High failure rates and short pump run times made forecasting of production volumes and reserves difficult, while high operating costs driven primarily by downhole servicing reduced the economic viability of the project.

The root cause of the high pump failure rate was attributed in most part to the unanticipated volume of produced coal fines and reservoir solids in the produced water stream. The production of these solids, coupled with lower than expected water production rates, led to a re-evaluation of the field's artificial lift strategy. Following a thorough artificial lift evaluation, a change from an ESP to a reciprocating rod pump (Pump Jack) system was initiated.

The largest anticipated benefit of reciprocating rod pumping systems over ESP artificial lift systems were:

Increased minimum flow path area through the system, reducing the frequency of solids plugging, leading to longer pump run times. Reduced well servicing costs with reciprocating rod pumps through elimination of services required solely by ESPs. Elimination of pump failures due strictly to electrical shortages by changing from an electrical/mechanical (ESP) to a straight mechanical (Pump Jack) downhole system. Improved operating efficiency by matching artificial lift design with actual water production rates.

The change in artificial lift strategy made an immediate impact on pump failure rates in the Doris field. This paper will present the resulting increased pump run times, sustained production rates and drastically lower operating costs that has made reciprocating rod pumping systems the artificial lift method recommended by Nexen to exploit Alberta's Mannville coal for CBM.
Key Parameters in Steam Chamber Development
Authors: Baker R. O. , Rodrigues K. , Sandhu K. S. , Jong E. S.
Published: February 2011

There is a large amount of reserves associated with heavy oil worldwide and as a result SAGD is reaching technological maturity and its implications on the future of the petroleum industry are considerable. Most of the theory of SAGD was developed in idealized lab models and flow simulations without accounting for much heterogeneity as well as operational effects.

Currently there are a large number of wells in SAGD projects with available production, injection, and pressure data that needs to be analyzed. In addition, there are thousands of pressure and temperature measurements, 4D seismic surveys, and tiltmeter surveys. It is essential to examine all of this available data and explore important factors like areal coverage of the steam chamber, vertical sweep, and residual oil saturations within the steam chamber, as well as the role that heterogeneity plays in the development of the steam chamber. It is our opinion that some of the empirical field case observations cannot be easily explained by conventional reservoir engineering, or even by current thermal simulation techniques.

By closely examining available production, injection, pressure, seismic, temperature logs for two different SAGD projects, this paper will show that there is a good correlation between the volume of the steam chamber (Vstm) as calculated by vertical temperature observation well data and seismic data, compared to the steam chamber size as indicated by oil recovery. When we use seismic data for estimating areal coverage and vertical observation wells for vertical coverage or sweep, it appears that the oil saturation slowly decreases in the steam chamber and displacement efficiency is slowly increases with time. This paper attempts to use all the available seismic data and data from observation wells in not just a qualitative analysis of the steam chamber, but to develop a method to analytically determine quantitative estimates for volumes of the steam chamber, areal displacement efficiency of the steam chamber, and remaining oil saturation in the steam chamber over time. Invesitgating available data from different observation wells along SAGD well pairs will show that steam chamber shape is far from uniform.
A New Method To Simultaneously Measure In-Situ Permeability and Porosity Under Reservoir Conditions: Implications for Characterization of Unconventional Gas Reservoirs
Authors: Cui X. , Bustin R. M. , Brezovski R. , Nassichuk B. , Glover K. , Pathi V.
Published: February 2011

Accurate estimation of gas-in-place is crucial for successful evaluation and exploitation of unconventional gas reservoirs, such as shale gas, coalbed methane, and tight gas. However, gas effective porosity, one of the most important parameter in estimating gas in-place, is commonly measured on crushed samples of cores or cuttings at ambient pressure although many studies have shown that the porosity and permeability of reservoirs rocks decrease with increasing effective stress, and thus the pore volume/porosity measured on crushed samples at ambient (zero stress) conditions will be larger than porosity measured under in-situ reservoir stress conditions. Normally the stress-dependence of porosity is simply accounted for by a correction factor based on the linear poro-elastic deformation, which is likely an over-simplification.

In present study, we developed a new protocol for simultaneously measuring stress-dependent In-Situ Permeability and Porosity (ISPP) that provides a method for routine characterization of effective porosity and permeability under simulated reservoir conditions. Our new method can significantly reduce the uncertainties of porosity introduced by testing crushed samples under ambient conditions, testing time, and the need for good quality core samples that are usually unavailable.

Preliminary test results indicate that the stress dependence of porosity (or pore compressibility) of fine grained reservoir rocks follows a unique trend of each tested sample, which cannot be simply adjusted from ambient porosity by a universal factor. Physical and numerical sample tests suggest that our ISPP method can obtain permeability similar to the normal pressure Pulse-Decay Permeability (PDP) technique if samples are homogeneous or transversely layered along their axes. Otherwise, our ISPP method likely tests the geometrical average permeability of longitudinally layered samples instead of the weighted arithmetical average permeability tested by the PDP method.

Overall, our approach of simultaneously measuring effective porosity and permeability under reservoir conditions offers intrinsically consistent porosity-permeability data to characterize unconventional reservoirs. Our study also reveals that utilization of different methods to test samples in different orientations and different sizes is necessary to rigorously characterize the hierarchical permeability and porosity of heterogeneous and microporous unconventional reservoir rocks.
Optimization of Hydrocarbon Additives With Steam in SAGD for Three Major Canadian Oil Sands Deposits
Authors: Mohebati M. Hosseininejad , Maini B. B. , Harding T. G.
Published: February 2011

Heavy oil and bitumen are expected to become increasingly important sources of fuel in the coming decades. There are extensive deposits in Alberta that could be a principal source of fuel in the coming century. The Athabasca Oil Sands, the largest petroleum accumulation in the world, the Cold Lake oil deposit, and the Lloydminster reservoir are all major Canadian oil sands deposits. SAGD, which has shown considerable promise in all three of these major deposits, remains an expensive technique and requires large energy input. Energy intensity of SAGD and the environmental concerns make it imperative to find new oil extraction technologies.

Co-injecting hydrocarbon additives with steam offers the potential of lower energy and water consumption and reduced greenhouse gas emission by improving the oil rates and recoveries. In a previous paper by the same authors(Hosseininejad Mohebati, Maini et al. 2009), it was shown that the selection of a suitable hydrocarbon additive and the effectiveness of this hybrid process are strongly dependent on the operating conditions, reservoir fluid composition, the heavy oil viscosity, and the petrophysical properties of the reservoir. Among these factors, the heavy oil viscosity which is the most prominent difference between these three reservoirs could be a very important parameter in the performance of this hybrid process. Therefore, it is important to evaluate the effect of oil viscosity on solvent assisted SAGD.

Extensive numerical studies in a 3D model by means of a fully implicit thermal simulator were conducted to evaluate the efficiency of each hydrocarbon additive in Athabasca, Cold Lake and Lloydminster reservoirs. Varying mole percents of hexane, butane and methane were co-injected with steam in with different values of heavy oil viscosity. The effect of oil viscosity on the performance of each solvent was compared in terms of oil production rate and cumulative steam oil ratio.