bluuebunny/crossref_metadata_2025 huggingface dataset:
Opportunity Generation in a 96% Depleted Billion Barrel Oilfield
Authors: Burnett Philip J.
Published: December 2007

In 2000, a multi-disciplinary technical team was formed to assess the potential remaining in a 96% depleted 1.3 billion BO recoverable oilfield complex (the Central Fields) in Bass Strait, Australia.

The first step was an extensive ‘data-mining’ exercise of the ~125 wells with ~500 completions in numerous reservoir units and 35 years of production history. This was followed by a period of geoscience/engineering collaborative analysis. A detailed field-wide reservoir correlation was integrated with production performance history and well-to-well interactions. These efforts resulted in the identification of an inventory of opportunities ranging from low-cost work-over operations to new drill-well candidates. A series of work-over operations performed from 2001 to 2004 yielded initial individual oil production rates of 1 thousand to 7 thousand BOPD and a total incremental reserve capture of over 10 million BO. In 2003, a two-well drilling program added in excess of 3 million BO recoverable with an initial production buildup of over 6 thousand BOPD

While relatively sophisticated techniques such as sequence stratigraphy and well performance modeling were important, these successful programs were primarily the result of rigorous data analysis and integration of geoscience and engineering workflows and were achieved with minimal advanced technology. Ongoing collaboration between geoscience and engineering will leverage off the documented results and incorporate future performance data to yield further insights and additional work-over and drill-well opportunities.
Oily-Water Treatment Schemes For Steam Generation in SAGD Heavy-Oil Developments
Authors: Pedenaud P. , Michaud P. , Goulay C.
Published: December 2007

Production of extra heavy oil or bitumen by means of SAGD (Steam Assisted Gravity Drainage) requires the generation and injection into the reservoir of a great quantity of steam. A corresponding quantity of hot water is then produced along with the mobilised oil. Bearing in mind existing and future environmental regulations, it is likely that partial or even total recycling of this produced water back into steam will become mandatory.

The complexity of the water treatment scheme required depends on the water characteristics, the steam boiler specification (OTSG or conventional 100% steam boiler) and whether or not waste water disposal is completely eliminated (zero reject) or not. SAGD developments have some specific water treatment issues which need to be addressed, for example the high silica content of the produced water. This paper will present different conceptual designs for a 300 000 bwpd water treatment plant. The different schemes discussed include an OTSG boiler, a conventional boiler and the zero disposal option. The various options available for process equipment will be presented, together with two different salinities of produced water and their impact on process design. Included will be an evaluation of capital cost and operating costs elements.
The Challenge Facing Multiphase Metering in Oil-Sands Thermal Developments
Authors: Arendo V. , Goulay C. , Stobie G. , Wall T. , Couput J. P.
Published: December 2007

Multiphase metering flow meters (MPFM) are being accepted more and more in oil and gas developments, replacing test separators, particularly on fields with large well networks. This is the case with Steam Assisted Gravity Drainage (SAGD) oil sands developments requiring large capital investment that need accurate production and reservoir data and have difficult processing techniques. This data includes: Real time measurement: good reservoir and steam chamber monitoring and steam injection versus oil production surveys.Cost reduction: steam oil ratio (SOR) optimisation, due to the economic and environmental cost of steam.Asset integrity: mitigation of the risk of steam breakthrough in oil producer wells.

The flow meters have to be sized for either viscous liquids (water in oil emulsions) or less viscous, but very hot liquids (oil in water emulsions) and to differentiate between gas and steam, or be able to meter the gas and assess the steam loading. In SAGD developments the water content determination is essential and the meters have to include qualified systems for both high temperature and high water cut measurements.

This paper outlines the business needs for MPFMs in SAGD and discusses the current difficulties with qualification, test loops, field trials and eventually, the perceived operational issues. The challenges facing multiphase metering in SAGD developments are as difficult as the industry faced when applying classical multiphase metering techniques several years ago. In order that these challenges are overcome it will be necessary for vendors and operators to develop and test the new technologies jointly. This will require that vendors dedicate sufficient effort in MPFM R&D and that operators participate in these developments, in JlP's and host field trials.
The Impact of Upgrader Location on Steam Generation
Authors: Michaud P. , Goulay C. , Sabbag J. N. , Thiery G. , Kehoe R.
Published: December 2007

Extra heavy oil (or bitumen) production through Steam Assisted Gravity Drainage (SAGD) requires large amounts of steam, which are classically produced by natural gas combustion using Once Through Steam Generators (OTSG). Steam production is a major SAGD operating cost, which has increased significantly with current high natural gas prices.

In order to reduce these costs or to mitigate for the risk of insufficient natural gas supply, several alternatives to natural gas for steam generation have been investigated, such as bitumen itself, coal, or ultra-low API "bottom of the barrel" residual by-products resulting from bitumen upgrading.

Two methods of utilizing these by-products are available: direct combustion and gasification. The advantage of gasification is that it produces desulphurized syngas that can be substituted for natural gas in conventional OTSG boilers. Gasification of asphaltenes to a synthetic gas (syngas) can be achieved by different technologies: partial oxidation (POX) technologies being the most widely known.

Whether or not an upgrader is present at the SAGD field site may dictate the type of fuel burnt or gasified and also the type of any gasification unit.

This paper describes the main conclusions of a study into the decision drivers for each steam generation alternative. A technical and economic model has been developed, which screens various extra heavy oil development scenarios.

This model has allowed an informed evaluation of the impact of upgrader location on steam generation cost and potential environmental impact, by considering CO2 emissions, possible upgrading by-products and their disposal and valorization for each scenario.
A New Gel-Foam System for Water Shutoff Purposes in Wormhole Reservoirs
Authors: Asghari K. , Taabbodi L. , Dong M.
Published: December 2007

Oil reservoirs in the Lloydminister region, Canada, are produced through the process of Clod Heavy Oil Production with Sand (CHOPS). Implementation of CHOPS in these fields causes the formation of wormholes, which leads to production of excessive water and abandonment of the wells. In order to reduce the excess water production from wormholes, variety of techniques have been suggested and tested with minimal success. Blocking the wormholes by the means of clay, polymer-gel systems, and gel-foams are among the proposed methods. This paper presents the results of a series of experiments conducted in order to develop and test the applicability of a new gel-foam system for blocking wormholes in oil reservoirs. As a result, a new gel-foam system was invented that creates stable foam in wormholes for the duration of gelation time. The composition of the gel-foam was based on polyacrylamide cross linked with chromium(III), plus a mixture of solutions of two commercially available surfactants. These commercially available surfactants were tested at various concentrations and ratios to develop the most stable gel-foam system. An experimental set up was designed and built which allowed for two layers of unconsolidated sand as the matrix separated by a high permeability wormhole between them. The effect of various sizes of wormholes on the performance of this gel-foam system was tested. All experiments were conducted at atmospheric pressure and constant temperature of 30°C, with some experiments in the presence of residual oil. For all the experiments the residual resistance factors to the flow of water in high permeability pathways were in the range of 25 to about 200. The results obtained are clear indication of the effectiveness of this newly developed gel-foam system for blocking wormholes and other high permeability pathways in reservoirs.
Investigation of the Vapex Process in High-Pressure Fractured Heavy-Oil Reservoirs
Authors: Rostami B. , Azin R. , Kharrat R.
Published: December 2007

In this work, the vapour extraction (VAPEX) process was studied in a multiple block, dual porosity fractured system. The performance of this process is compared with a conventional, non-fractured system under similar rock and fluid properties, bulk volume, pore volume, hydrocarbon volume, and injected pore volume of solvent and solvent injection rate. At early stages of the VAPEX process in fractured system, the solvent-oil interfaces form and develop from all sides of the matrix, and the oil chamber, rather than solvent chamber forms and shrinks in the center of each block. Also, at later stages of the process, the solvent zones from all neighboring blocks combine and form an integrated solvent zone, which is similar to that in the conventional systems.

The results showed that in low-permeability carbonate reservoirs, the fracture network provides communications for solvent flow through which the solvent can flow faster and form solvent fingers at early stages, which can reach the blocks located at farther distances from injection well. It was found that the solvent breakthrough starts at he same time in both low-permeability non-fractured system and fractured system. This is because the solvent flows directly through drained areas towards producer in both systems.

Further, effect of solvent injection rate on heavy oil recovery in the fractured system was studied in two cases: different injection rate at the same injection time, and different injection rate with the same injected pore volume. It was found that the solvent injection rate should be optimized for a specific system in order to control the solvent breakthrough and to avoid extra operation time and cost.
Application of Resin System for Sand Consolidation, Mud-Loss Control, and Channel Repairing
Authors: Wasnik A. , Mete S. , Ghosh B.
Published: December 2007

This paper describes a method of sand consolidation and channel repairing by using a Resin system, the system comprises of a resin (a mixture of elastomers UF, MF and a suitable plasticizer) and a hardener (a mixture of two mild Lewis Acids). The hardener controls curing time. The role of plasticizer is to impart flexibility and impact resistance to otherwise brittle natured UF-MF resin. Surface bonding between Sand and resin has been enhanced with a special additive, if required.

This paper also describes a methodology of placing a chemical casing during or after drilling a caving prone shale zone, strong enough to prevent sloughing of shale and withstands mechanical shocks during drilling, which would facilitate drilling with reduced mud weight and without reduction of hole size.

Experimental results on resin development and mechanical parameters of sand consolidation and Chemical casing of different mineralogy have been presented. The compressive strength of the consolidated sand and shale is found to be extremely high to withstand the overburden pressure and mechanical impacts during drilling. The designed application methodology is described in detail.

This system would be extremely economic as it can be applied directly after perforation if required, saving rig time and reducing completion cost compared to Gravel pack, liner placement and Screens, with the added advantage of no hole size reduction and better sand consolidation as compared to other methods. The developed chemical system is 1/3 the cost of epoxy resins, reported earlier for similar application and the components are environment friendly and easy to handle because of their water solubility.
In-Situ Bitumen Overview and Activity Update in the Province of Alberta
Authors: Sadler K. , Davis P.
Published: December 2007

The Alberta Energy and Utilities Board regulates all energy-related operations, including bitumen and heavy oil recovery activities, in the province of Alberta. With the high petroleum commodity prices in recent years, activity and investment levels in this sector have increased dramatically and are forecast to increase even more in the foreseeable future. New and innovative technology is moving rapidly from the laboratories to field implementation to increase recovery rates, improve operational efficiencies and reduce costs.

This paper presents a brief overview of the current regulatory process for the in situ thermal bitumen recovery sector. There is a discussion on the major regulatory issues associated with the in situ bitumen recovery projects. A summary of the bitumen reserve statistics and production forecasts, broken down to the recovery technologies, is also provided.
Advances in Oil and Water Saturation Measurements Using Low Field NMR
Authors: Bryan J. , Mai A. , Hum F. , Kantzas A.
Published: December 2007

Low field nuclear magnetic resonance (NMR) relaxometry has been successfully used in the past to perform in-situ estimates of oil and water content in unconsolidated oil sand samples. This work has intriguiging applications in the oil sands mining and processing industry, in the areas of ore and froth characterization. Studies have previously been performed on a database of ore and froth samples from the Athabasca region in northern Alberta, and preliminary results have been encouraging. In this paper, supporting data is presented and refinements suggested to the previous algorithms, to improve the oil and water saturation predictions.

A suite of real and synthetic samples of bitumen, water, clay and sand have been used to investigate the physical interactions of the different components on the NMR spectra. An automated algorithm is used to separate the oil and water NMR signals, and this algorithm is tested against samples both from this zone and from other heavy oil fields. Moreover, preliminary observations regarding spectral properties indicate that it may be possible in the future to estimate the amount of clay in the samples, based upon shifts in the NMR spectra. NMR estimates of oil and water content are fairly accurate, thus enhancing the possibility of using NMR for both in-situ oil sands development and in the oil sands mining industry.
Heavy-Oil Fluid Testing With Conventional and Novel Techniques
Authors: Goodarzi N. , Bryan J. , Mai A. , Kantzas A.
Published: December 2007

In this paper, we propose the combined utilization of x-ray tomography and magnetic resonance techniques for quantification of heavy oil fluid properties. The design of these systems is presented along with preliminary results combined with conventional measurements. The objective is to understand the PVT behavior of a viscous heavy oil from a reservoir that has undergone primary production. Methane is dissolved into the oil at ambient temperature and elevated pressure. The pressure is later slowly depleted and the oil PVT properties are recorded. Specifically, this paper details measurements of oil density, formation value factor, and solution gas-oil-ratio as a function of pressure. The incremental benefit of the proposed nucleonic techniques is that they provide more detailed information about that oil, compared to conventional PVT measurements. This improves our understanding of the foamy oil response.
Mapping Reservoir Volume Changes During Cyclic Steam Stimulation Using Tiltmeter-Based Surface-Deformation Measurements
Authors: Du J. , Brissenden S. J. , McGillivray P. , Bourne S. , Hofstra P. , Davis E. J. , Roadarmel W. H. , Wolhart S. L. , Marsic S. , Gusek R. , Wright C. A.
Published: December 2007

Surface deformation measurements have been used for years in oilfields to monitor production, waterflooding, waste injection, steam flooding, and Cyclic Steam Stimulation (CSS). They have been proven to be a very effective way to monitor the field operations and save money for operators wishing to avoid unwanted surface breeches, casing failures and excessive subsidence due to production. This paper demonstrates that more information can be extracted from surface deformation measurements by inverting the surface deformation for the volumetric deformation at the reservoir level, so the aerial distribution of volumetric deformation can be identified. First, a poroelastic model is presented to calculate the deformation due to the volumetric change in the reservoir. Then, a linear geophysical model is formulated to invert for the reservoir volumetric deformation from the measured surface deformation (or tilt). Constraints are added into the procedure as necessary to better resolve the inversion problem. After each inversion, the theoretical surface deformation (displacement, tilt, reservoir compaction and volumetric strain) can be calculated from the inverted volumetric deformation distribution which best fits the measured deformation data (or tilt) at the surface. The technique of mapping fluid flow using surface deformation was applied to real data from a cyclic steam injection project.
Experimental Observations of Miscible Displacement of Heavy Oils With Hydrocarbon Solvents
Authors: Salama D. , Kantzas A.
Published: December 2007

The increased interest in secondary production (or post-cold production) of heavy oil and the current rise of oil prices has renewed interest in solvent-based methods for heavy oil recovery. Although the Vapor Extraction (VAPEX) process is the most heavily favored process for potential field application, other methods are also worth investigating. Moreover, the relative merit of mass transfer and viscous mechanisms in the overall recovery efficiency remains a topic of debate in the literature.

This paper is a small part of a greater effort to study mass transfer phenomena in heavy oil/bitumen solvent systems. A series of core flooding experiments were performed whereby liquid solvents (octane, pentane) displaced heavy oil (12Pa.s). Different configurations and displacement rates were employed and heavy oil recovery factors were determined. Solvent concentrations in the effluent oil-solvent mixtures were accurately evaluated using the non-intrusive Nuclear Magnetic Resonance (NMR) technique and conventional density measurements.

Mass transfer analysis was performed in an effort to determine dispersion coefficients.
Effect of Formation Damage to Production Performance in Heavy-Oil Reservoir via Steam Injection After Waterflooding
Authors: Xiao G. , Zhimin D. , Yu F. , Lang L. , Xingguo Z. , Jin H.
Published: December 2007

Heavy oil reservoirs of steam-injection development after water-flooding have normally experienced many different production processes, such as cold production, water-flooding, steam buff and puff, and steam flooding. Some complex phenomena and effects may occur in the non-isothermal recovery processes, for example, distillation, decline in in-situ oil viscosity, water gravity segregation, steam overlap, the development of wormholes, forming foaming oil, thermal expansion effect of formation fluid and rock, and reversed wettability. Simultaneously, formation damage induced by clay swelling, external particles invasion, fines generation, migration, sanding and asphaltene precipitation may happen, which can lead to variations in formation permeability and porosity and significantly reduce oil production rate and even lead to its complete loss. Traditional model for simulating heavy oil reservoir production behavior has not allowed for the influence of formation damage on heavy oil reservoir and has neglected dynamic changes in formation porosity and permeability. Thereby, it becomes unreliable to design and adjust development plan and forecast production performance in heavy oil reservoir via steam-injection after water-flooding. In this paper, a 3-D, 3-phase, compositional thermal simulator NUMSIP (Numerical Model for Steam Injection Processes) has been reworked and further developed, considering formation damage induced by clay swelling, fines migration and asphaltene precipitation. Based on the laboratory experiments, formation damage was determined and our in-house new simulator has been successfully applied in Liudong Section heavy oil reservoir in Xinjiang Oil Field. The objective of this work was to investigate and illustrate how much formation damage impacts heavy oil reservoir production performance and the work also suggests dynamic changes in porosity and permeability should be considered globally to correctly predict production performance in heavy oil reservoir via steam-injection after water-flooding.
An Exact Downscaling Methodology in Presence of Heterogeneity: Application to the Athabasca Oil Sands
Authors: Ren W. , Mclennan J. A. , Cunha L. B. , Deutsch C. V.
Published: December 2007

Geostatistical realizations are often built at an arbitrary scale based on available data and computational resources. In certain settings, it may be necessary to downscale the realizations for flow simulation and local resource assessment. This is especially important in the Athabasca Oilsands where accurate flow simulation often requires numerical models with a very fine grid size. Flow simulation is undertaken for selected areas and realizations. It is intractable to construct the original geostatistical models at the fine scale. It is desirable to construct finer scale models that reproduce the original realizations exactly.

Approximate downscaling is always possible with geostatistical methods; however, it is of interest to create fine scale models that exactly reproduce the large scale models to ensure consistency and avoid potential biases. Direct block sequential simulation is developed to generate fine scale realizations that exactly reproduce block data.

A comprehensive case study is shown from the Athabasca Oilsands. Geostatistical realizations are constructed over 100s of square kilometers at a large scale. These realizations are locally downscaled to 20m by 2m by 2m for flow simulation around particular SAGD well pairs. The fine scale realizations are constructed such that they exactly match the initial coarse scale realizations. An approximate downscaling method is also used. The 3-D models and flow simulation results were compared to show the difference made by the exact downscaling method.
Water-Assisted Flow of Heavy Oil and Gas in a Vertical Pipe
Authors: Bannwart A. C. , Vieira F. F. , Carvalho C. H. M. , Oliveira A. P.
Published: December 2007

The three-phase water-assisted flow of heavy crude oil with free gas (air) in a vertical glass pipe, at near atmospheric pressure and temperature conditions, is investigated, for possible applications to the articial lift of heavy oil. Water is injected so as to avoid oil-wall contact and reduce friction. The oil phase was a w/o emulsion with a viscosity of 5,040 mPa.s and a density of 971 kg/m3. For each combination of oil-water-gas flow rates, the flow pattern was determined using a high speed camera and the pressure gradient was measured with a differential pressure transducer. The results are presented in the form of flow maps based on superficial velocities and total pressure gradient plots, allowing comparisons with well known correlations. The main conclusion indicates the great viability of the water-assisted flow technique. Significant amounts of heavy oil have been discovered in offshore Brazil.
Integrated Well-Completion Strategies With CHOPS To Enhance Heavy-Oil Production: A Case Study in Fula Oilfield
Authors: Wang X. , Zou H. , Li G. , Nie C. , Chen J.
Published: December 2007

Fula oil field is composed of unconsolidated sandstones, buried as deep as 3500ft, with high porosity (31%) and permeability(2 Darcy), producing viscous oil with 19-21°API on the south flank of Muglad Basin. It is well-known that under proper conditions formation flow characteristics can be improved by non-thermal massive sand production and foamy oil behavior, referred to CHOPS.

Integrated well completion strategies with CHOPS were used to increase heavy oil production. Limited sand influx provides a means for effective sand control while eliminating the need for conventional sand control processes. The principle of limited sand flux is ‘coarse sands controlled and finer sands produced’, which is using the screen liner to inhibit 0.5mm or larger sands flowing into the wellbore, in addition, the rest smaller solids can be produced to the surface by viscous oil.

Experiments were conducted to study the capability of lifting sands by crude oil. It showed that the sand of 0.9mm can be allowed to move up with heavy oil to the surface while 510 mPa.s of viscous oil is lifted in 3 1/2 in tubing. Using progressing cavity pump deliberately initiated sand influx but only 15% solids were controlled to form wormhole to improve permeability of the pay zone.

This paper describes initial field test results of the new system that 20 heavy oil wells were equipped with PCP which is helpful for handling sanding effectively. The sand cuts range from 0.1 to 12% by volume. Average oil rate of each well is up to 580bopd from 175bopd before CHOPS. The best well can produce as much as 1200 BOPD. Oil production has reached to 2,450,000 bbl/y with attractive result.
Optimized Abandonment Procedures Improved Success and Results in Central California Heavy-Oil Field
Authors: Glessner D. , Dean M. , Haire M. , Bour D.
Published: December 2007

This case-history paper presents the development background and detail of optimized procedures followed to plug and abandon wells in a cyclic-steam well in central California. Improvements that resulted in the success are detailed and explained.

Abandonment processes included identification, using tilt-meter events, of holes in casing and/or casing parting. Temperature surveys and/or radioactive surveys confirmed and located depth of the hole in the casing. Specific procedures were then followed to abandon the well below the part, at the part, and then above the part in the casing. Inspection and testing of the casing were also conducted to help ensure that additional holes were not present in the casing before the abandonment was complete. In the rare instances that additional holes were found, they were squeezed off separately with cement. Key to the success of this procedure was squeezing thixotropic cement instead of setting balanced plugs across zones of interest. This method allowed for short turn-around times to resume operations and helped ensure that the cement remained where it was originally placed.
PDA Program for Small Producing Companies
Authors: Cook J. R.
Published: December 2007

Current technologies create the possibility of gathering oil field data through the use of Personal Digital Assistance (PDA). PDA can provide a convenient means of transferring and storing data.

The problem that many small production companies experience is in the cost of creating or purchasing a system that utilizes PDAs.

This paper identifies the needs of production companies and describes a program, which can be used by production companies.
Geology and Geometry: A Review of Factors Affecting the Effectiveness of Hydraulic Fractures
Authors: Willis R. B. , Fontaine J. , Paugh L. , Griffin L.
Published: December 2007

Thousands of wells are hydraulically fractured in the Appalachian Basin each year with little clear understanding of what the resulting fracture actually looks like. A number of variables exist in the subsurface including natural fractures, permeability variations, in-situ stresses, faults, etc. that can influence the ultimate dimensions and orientation of the created fracture. It is necessary that the stimulation design team understand the impacts that these features can have on the path a hydraulic fracture takes in the subsurface. The created fracture and its conductivity ultimately dictate a well's productivity and drainage area.

This paper will outline the basics of how in-situ stresses affect the orientation of propagating hydraulic fractures and how some geological characteristics can impact the process. Some discussion will be presented on the current technologies being used to understand fracture geometry. These include microseismic imaging and tiltmeter surveys.
The Effect of Using a Lightweight Proppant in Treatment of a Low-Permeability, Dry Gas Reservoir: A Case Study
Authors: Posey D. , Strickland B.
Published: December 2007

The Mesaverde formation is a low permeability gas sandstone reservoir and a primary completion target in the San Juan Basin of northwest New Mexico and southwest Colorado. In over 50 years of Mesaverde development activity, varying completion and stimulation techniques have been tried in an effort to find the optimum method for enhancing long-term production. Initially, production and economic analysis indicated that high rate slickwater jobs using 20/40 mesh sand (specific gravity = 2.65) proved most effective. One attribute of the slick water approach is that the relatively heavy fracturing sand falls rapidly through the low-viscosity water and forms a bank of proppant over a very limited percentage of the total fracture area created with the hydraulic fluid (water.) As the field matured, reservoir pressure depleted and drilling cost escalated, the need arose for a different stimulation approach creating more extensive area open for fracture flow and reservoir drainage enhancement. To address this need, a lightweight proppant (specific gravity = 1.25) was substituted in lieu of fracturing sand with the idea of placing a partial mono-layer of proppant across a very large percentage of the total fracture area. This paper is a case study of six recent offset Mesaverde completions comparing the productivity of wells stimulated with all 20/40 mesh sand, all lightweight proppant and a hybrid approach utilizing a stage of lightweight proppant followed by a stage of 20/40 mesh sand. Post-fracture hourly flow rates and wellhead pressures were analyzed in all cases to access effectiveness. Wells treated with all lightweight proppant were found to have the most sustained well productivity and stimulation effectiveness.
Computer-Based Engineering Evaluation on Underground Waterflooding Fields in the Appalachian Region
Authors: Zaghloul J. , Farías M. , Ertekin T. , Watson R.
Published: December 2007

The Appalachian region contains hundreds of oil fields that were developed during the late 1800's and early 1900's. These fields contain oil reserves that may be recovered using secondary recovery methods such as waterflooding. Technical and economic evaluation of these fields for these capital-intensive operations requires in-depth engineering studies that usually include a field-scale computer model.

The objective of this study is the computer based engineering assessment of the mechanisms attendant to waterflooding of Gordon sandstone fields located in the Appalachian basin. To accomplish this objective, two case studies are presented. One is the Washington-Taylorstown field in Pennsylvania and the other is the Wileyville field in West Virginia.

The computer models developed include the history matching of the production data and the analysis of dynamic skin factor. The history matching protocol utilizes a systematic approach to complete the simulation of the historical data, which proved to be effective in understanding the behavior of the reservoir under study. It was concluded that the change in skin with time in waterflooding operations is not only due to matrix permeability variations; but also external factors such as mixed fluids injection, suspended particles and particle deposition.

The results obtained provide the operators of the Appalachian basin with a tool to characterize, initialize and perform computer simulation studies of any of the hundreds of reservoirs in the basin.
Stripper Well Consortium Offers Opportunities and Technologies to the Stripper Well Industry
Authors: Covatch G. L. , Morrison J.
Published: December 2007

As the United States moves to become less energy dependent on foreign sources, the importance of production from domestic stripper oil and gas wells will be much greater than it is today. Currently, stripper oil wells account for 15 percent of total domestic oil production and stripper gas wells account for 8 percent of total dry gas production. The importance of stripper wells is also reflected in that they represent 77 percent and 63 percent of the country's total oil and gas well populations respectively. Therefore, developing inexpensive technologies will be key in keeping these wells productive and helping the nation meet its energy demand.

In an effort to help maintain the production from stripper wells, the Department of Energy provides funding to the Stripper Well Consortium (SWC) to develop and demonstrate technologies that will improve the production performance of stripper wells. The SWC was established in 2000 and has cofunded over 60 projects since its inception. The SWC is an industry-driven organization and all projects are selected by a seven-member Executive Council elected for member organizations. Several projects have been completed and are now being offered commercially. This paper will focus on the operation of and the opportunities offered by the SWC, as well as highlighting a few of the successful projects such as the Gas Operated Automatic Lift (GOAL) PetroPump, the Vortex flow tools, the hydraulic diaphragm electrical submersible pump, and the new novel Weatherbee pump/compressor.
Review of Current Fracture Stimulation Techniques for Best Economics in Multilayer, Lower-Permeability Reservoirs
Authors: McDaniel B. W.
Published: December 2007

Currently, thousands of wells are being drilled every year in low- to moderate- permeability sandstone and carbonate reservoirs that have many distinct zones or layers that can contribute to production if adequately stimulated. In lower-permeability reservoirs, and especially for CBM completions, well economics will limit how much can be spent on the stimulation portion of a completion program. Operators may have to execute a "balancing act" with the need to maximize return on investment (ROI) while trying to complete as many contributing zones as possible. This usually drives a well operator toward methods that can minimize the number of separate well interventions while maximizing the number of zones that can be effectively stimulated.

This paper provides a State of the Art review on both old and newer completion/stimulation techniques that can help an operator accomplish production goals. When the fracturing treatments are pumped down the casing, different methods applied can vary from simple, single-stage fracturing treatments using "limited entry" perforating to multi-stage fracture treatments with bridge plugs (BP) or ball/baffle stage isolation. Additionally, there are various other techniques incorporating conventional tubing strings with or without packers or BP's, and even various methods for coiled-tubing (CT)-deployed treatments.

A "scorecard" approach presented here may offer operators an improved understanding of when a certain completion method is appropriate or flawed, based on the operators’ current understanding of specific reservoir characteristics of their field or well. Too often, a multilayer completion technique has been applied to several wells and later found to be a poor choice. The wrong choice may have been made because of a limited understanding of the completion method, or even of the reservoir itself. Often, an operator understands the variances of the reservoir, but does not realize the limitations that these variances should bring to the process of choosing the optimal simulation/completion method. In some cases, the choice has simply been made to take the low-cost completion/stimulation approach, and the resulting well(s) did not produce at (or sustain) economic levels.
(HC)3 Hydrocracking Technology
Authors: Lott R. K. , Lee T. L. K. , Quinn J.
Published: December 2007

Refineries are processing bottoms and heavy oils to lighter products using either thermal cracking base technologies such as visbreaking, delayed and fluid coking, or solid catalyst base low to moderate hydroconversion technologies using fixed bed and ebullated bed reactors. Unconverted resid from ebullated bed reactor has also been fed to delayed coker to increase the distillates yield. These processes perform well for what they are designed to do. With the new fuel specifications of 10–50 parts per million sulfur restriction in transportation fuels, distillates produced from low conversion fixed bed and ebullated bed hydroprocessing will not meet the required ultra low sulfur content without further hydrotreating. For distillates produced from delayed and fluid coking, even more severe secondary processing is needed to reduce the aromatic and sulfur contents in order to meet the new fuel regulations. In light of the current high crude price, general decline in crude quality, and regulations mandated high quality, ultra low sulfur specifications for the transportation fuels, significant advantages exist for flexible technology that can overcome limitations of current bottoms of the barrel upgrading processes.

The Alberta Government formed the Alberta Oil Sands Technology Research Authority (AOSTRA) in the 1970's to fund research and development of technologies to improve the economics of producing synthetic crude oil from its vast reserves of heavy oils and oil sands. These research programs provided new insight on the molecular structure of heavy oil, the chemistry of the various non-volatile fractions, especially on their tendency to form carbonaceous solids (coke) during upgrading. In the mid-1990's researchers at the Alberta Research Council (ARC) and AOSTRA developed a new upgrading technology called (HC)3TM, a hydro-conversion process that is designed to efficiently convert bottoms and residua rich in metals and asphaltenes to lighter products.

In 2001, Headwaters Heavy Oil, Inc. (HHO), obtained a worldwide exclusive license from the Alberta Science and Research Authority (ASRA) to commercialize and market the (HC)3TM hydrocracking technology. The This paper describes the (HC)3TM technology, its applications to improve operations at existing supported catalyst hydroprocessing facilities and as a stand alone hydrocracker.
Strategies for Unraveling the Mystery of Low-Resistivity Pay Zones
Authors: Myers R. R. , Batcheller G. , Phipps S.
Published: December 2007

In the Appalachian Basin gas wells are air-drilled and a multi-zone well stimulation are the normal completions. The majority of these wells are logged with air in the hole after removing the fines from drilling using compressed air. The sandstones in the Devonian series of the Appalachian Basin are listed in Table 1. These are associated with thinly bedded laminated sand shale sequences causing the Resistivity log to be lower. Many producing gas zones may be defined as so-called low resistivity pays.

Table 1 After Laughrey and Harper7, 1986, listing of gas well targets in Pennsylvania. Devonian Riceville Formation Venango Group Gantz Fifty-Foot Thirty-Foot, Upper Nineveh Snee, Lower Nineveh Gordon Stray, Boulder Gordon, Third Fourth Fifth Fifth Stray Bayard Bayard Stray Elizabeth Chadadoin Formation Pink Rock Bradford Group First Warren Second Warren Third Warren Speechley Stray, Upper Speechley Speechley Tiona First Balltown Second Balltown Sheffield, Third Balltown First Bradford Second Bradford Third Bradford Kane Elk Group Haskill, Riley, Elk Benson, Humphrey Alexander

Normal logging programs do not respond properly to thin or very thin pay zones which will be averaged with surrounding shales. This log response can cause pay zones to be overlooked as stimulation candidates. Information can be found from openhole logs in air filled holes, using a different methodology, to more accurately determine producing gas zones.

Appalachian Basin gas zones of the Upper Devonian section will be analyzed. A strategy will be recommended to help determine which zone(s) contain producible gas reserves or may not be worthy of hydraulic fracturing treatments. These decisions could have significant economic implications for operators. Appalachian Basin log examples, stimulation design and production response will be included as part of this investigation.
Crosslinked Gel Provides Long-Term Control of High-Pressure Gas Well During Coiled-Tubing Fishing: Challenges and Success Story
Authors: Nwoke L. A. , Uchendu C. V. , Ubani O. O. , Button J. , Arukhe J. O.
Published: December 2007

Identifying suitable kill fluids to temporarily control prolific oil and gas reservoirs without risk of formation damage has been a challenge within the Niger Delta. Various attempts, particularly in gas wells using conventional brines and gels to enhance well intervention processes normally require stimulation treatments, in order to bring the wells back to production.

The engineered cross-linked gel is a temporary blocking formulation used to protect permeable zones from invasion of fluids. This system contains a low-residue cellulose-polymer with a cross-linking agent and can be designed for use with an internal or external breaker. In general, the use of loss circulation material (LCM) is not recommended because of its tendency to block perforations, complicate fishing operations and increase the difficulty of clean-up if fishing becomes unsuccessful.

This case study is of a gas well drilled and completed for an Operator on the E4.2-reservoir with production capability estimated at 8,000 bbl/day of condensate and 150 mmscf/day of gas. Following the installation of the memory gauges, a 10- hour build-up test of this particular interval was conducted. During the retrieval of the BHP gauges, several incidents lead to three successive fishes getting stucked into the wellbore. The Operator was faced with many challenges: ‘do nothing and produce the well in an unsafe manner at 50% potential’, ‘attempt a workover’ or ‘attempt a coiled tubing rigless intervention’, with each option having its attendant limitations.

The success in retrieving the multiple fishes was attributed to the ability to kill the high pressure gas well with a time dependent and acid degradable cross-linked gel system through a high rate bullhead pumping technique. The gel had low damage potential to the formation and prevented the migration and fingering of formation gas to the surface throughout the fishing operation that lasted for approximately one month on 24-hour daily operations. The pre-fishing conduit potential was preserved, indicating that the cross- linked gel completely got degraded internally at the end of the fishing operation leaving the near wellbore region undamaged.

In this paper, the laboratory simulation, features, engineering design, field application and benefits of the engineered cross- linked gel system are discussed. In addition, the process of well killing, specialized coiled tubing and wireline fishing tools and performance evaluation are addressed. The success of the operation includes regain of the original well performance, competence in well killing and complex fishing, cost savings and high NPV. Over $2.0 million was saved operationally with the CT rigless activity when compared to ‘workover’ or ‘do nothing’ options.
Rock Physics and Time-Lapse Monitoring of Heavy-Oil Reservoirs
Authors: Schmitt D. R.
Published: December 2007

Production of hydrocarbons from heavy oil reservoirs often requires large investments both in capital and in operation and despite the best efforts portions of the reservoir may be bypassed or injected fluids may be lost. Time-lapse geophysical methods have shown promise in monitoring such reservoirs, particularly in the case of weakly consolidated sands. The seismic response can depend on a variety of factors that include temperature, pore pressure, stress, fluid saturation state, and material damage. These effects are briefly reviewed in the context of Gassmann's relation that predicts the compressibility, rigidity, and density of a saturated porous rock. While Gassmann's relation is widely used in fluid substitution studies, it is not yet clear whether it can be appropriately applied in the context of viscous heavy oil reservoirs.
Results From a Field Trial Using New Additives for Fracture Conductivity Enhancement in a High-Gas Screenless Completion in the Jauf Reservoir, Saudi Arabia
Authors: Al-Ghurairi F. , Solares R. , Bartko K. , Sierra L.
Published: December 2007

Saudi Aramco has been conducting a successful fracturing for sand control strategy in high pressure/temperature high gas rate screenless completions in the Jauf sandstone, which exhibits high sanding tendency in certain zones throughout the reservoir. The strategy combines a number of techniques, including indirect fracturing from oriented perforated thin consolidated zones, tip screenout design, use of a combination of resin coated proppant (RCP) with fibers, forced closure, and a carefully controlled flowback procedure.

Although solids-free high rate gas production has been achieved in the majority of wells for which the strategy has been implemented, a reduction in fracture conductivity in the form of positive skin has been detected in several hydraulically fractured wells in which pressure buildup tests have been conducted. Part of this negative effect results in all likelihood from partial perforation effects, given that the interval from which a fracture is initiated is usually perforated in high Young's Modulus rock and limited to 30-40 feet. Thus, the fracture is initiated away from the high sanding tendency zones and extended into such zones. The other main component for the positive skin are the fibers used for proppont flow back control purposes since it is well known through extensive industry testing that the combination of resin coated proppant and fibers can reduce fracture conductivity in treated wells.

Lab testing aimed at identifying potential conductivity reduction mitigation techniques, while maintaining the ability to achieve effective formation sand control, showed that the combination of two new additives, when mixed with proppant, was able to achieve both key requirements. Hence a suitable candidate was selected for a field trial.

This paper discusses the results of the first field trial of the additives tested as an alternative to the resin coated proppant/fibers mixture and the lessons learned from the trial. A direct comparison between the well treated with the new additives and an offset well previously treated with resin coated proppant and fibers, showed that the well treated with the new additives yielded better productivity despite the fact that its kh was only 1/3 of the kh of the offset well. A posttreatment pressure buildup tests was conducted in each of the wells for a valid comparison.