bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Innovative Technologies to Fractured Devonian Shale Reservoir Exploration and Development Activities
Authors: MacDonald R. J. , Frantz J. H. , Merriam G. W. , Zyglowicz P. A. 
Published: December 2007

Abstract
This project was conducted under the auspices of NYSERDA contract 4881-ERTER-ER-99 with its primary purpose to obtain and utilize "ground-truth" data collected from two Upper Devonian Shale wells. With this information, a better understanding of the productive potential in western New York has been obtained. Both wells (W. Stein Unit #2 and S. Preston #8) were drilled in August 2001 by Great Lakes Energy Partners, LLC and are located in Athens field, Crawford County, Pa. adjacent to the Tyrone Mount Union lineament. The wells were completed open hole without any stimulation. Numerous technologies were used to acquire this information including running geophysical logs, gas sample analysis, and examining ten rotary sidewall cores from the Stein Unit #2. From this data, various models were built to characterize geologic, reservoir, and fluid flow characteristics, which were used to estimate gas in place, bulk permeability, and deliverability.
Though the existent natural fracture systems provide conduits from the reservoir to the wellbore, the shale in this area contains only a limited quantity of gas-in-place and is exceptionally lean in organic content. Permeability studies indicate this is a dual porosity system producing primarily via the fractures, and to a lesser extent from the matrix. Very little adsorption of gas is present and the reservoir is relatively low in organic content. An analysis conducted by the University of Michigan reveals that the gas is primarily thermogenic in origin with possible traces of biogenic origin. The results of this paper are significant in that it provides a better understanding of the production mechanisms of the reservoir within a localized area.
Based on the results of this study, the following conclusions are provided: The Upper Devonian Shale in this immediate area is extremely lean in organic content as indicated by its low Total Organic Carbon (TOC) = 0.36%. As a point of reference, many productive shales have TOC values ranging from 1-9%.Shales in this immediate area are a limited source of hydrocarbons (~27 Mscf per acre-foot).The gas is thermogenic with trace amounts of biogenic origin.Very little adsorption of gas is present.Both test wells are located in an area of natural fracturing adjacent to the Tyrone Mount Union lineament, which most likely provides a conduit for natural gas production.Relative to other producing shales, the reservoir is comparatively poor near the test wells.Production data analysis indicates a dual porosity system producing primarily through fractures and to a lesser extent, via the matrix.Estimated ultimate recoveries range from 1.1 to 3.0 MMscf, and drainage areas are 1.325 and 2.0 acres for the Preston #8 and Stein Unit #2 respectively, assuming no stimulation.
The Relationship Between Net Pressure Development During Hydraulic Fracture Treatments and Productivity in Fruitland Coal Completions
Authors: Jordan Jeff S. , Harkrider John D. , Anthony William L. , DeLong Thomas W. , Martin Ray F. 
Published: December 2007

Abstract
This paper describes an innovative fracture treatment design approach that has been successfully used to improve the productivity of Fruitland coal CBM completions. The process integrates real-time treating pressure evaluation to adjust key treatment parameters on the fly and maintain a low net pressure development. The low net pressure development indicates good proppant distribution through the created fracture geometry and minimizes potential formation/fracture damage from the fracturing fluids. This results in shorter de-watering periods and accelerates peak production of the Fruitland Coal completions.
In the Fruitland Coal, the dominant fracturing mechanism controlling the ability to distribute proppant laterally into the far-field is the quality of the near-wellbore connection. Complex near-wellbore fracture geometries result in a convoluted slurry pathway, which hinders lateral proppant distribution into the far-field. Further, if the near-wellbore connection was not mitigated effectively, the overall net pressure development while placing proppant became excessive. This paper discusses the innovative changes made to improve the near-wellbore connection, allowing the treatment to be completed and productivity of the well increased.
Based on an offset well study, it was observed that excess net pressure development damaged the fracture conductivity and/or the cleat system of the coal. When an excessive level of net pressure was developed, polymer dehydration into the cleat system caused irreparable damage to the existing permeability. Evidence of the damage was indicated by the extended load fluid recovery time. Since de-watering of the coal begins only after the load is recovered, it was observed that gas production was significantly delayed when the net pressure development during the propped fracture treatment was excessively high.
Observing this relationship, treatment designs were altered, but more importantly, real-time assessment of the treatment pressure character was found to be essential in achieving design objectives. The completion approach discussed in this paper has been employed in over thirty-five Fruitland Coals completions over the past three years with excellent production results.
Analysis and Optimal Design of Gas Storage Reservoirs
Authors: Kuncir Mark , Chang Jincai , Mansdorfer Jim , Dougherty Elmer 
Published: December 2007

Abstract
Gas storage plays an increasingly important role in managing gas supply. Developing and operating gas storage reservoirs more effectively is a key component of minimizing cost and assuring continuous supply to consumers[1,2,3]. Here we demonstrate the benefits gained from use of a comprehensive set of computer tools to interpret performance and devise optimal operating and investment plans for storage reservoirs. These tools treat engineering and economic factors simultaneously in an integrated framework. However, speed and convenience are achieved via use of aggregated models. Efficient search and curve-fitting routines allow rapid assessment of potential impact of missing or uncertain data. These programs are especially useful in the planning stage of storage reservoir development where complex multi-cell reservoir simulators may not be cost effective.
In this paper, we present the results of four case studies: Final blowdown of a storage reservoir.Optimal design of expansion of a storage reservoir.Size and impact of a storage reservoir&#39;s aquifer.Potential impact of data uncertainty on an oil reserve estimate.
Paraffin Problems in Gas Systems
Authors: Barker K. M. , Bigler J. M. , Hake K. , Sallee D. C. 
Published: December 2007

Abstract
Gas wells, coal seam methane wells, glycol dehydrators, gas plants and gas storage wells can all experience paraffin problems that affect the cost to produce and handle gas. Problems with paraffin have been encountered from the formation through the gas plants to the storage wells. This paper will explain what paraffin is, why the problems occur and what type of treatments have effectively treated gas system problems. Case histories of various types of successful and unsuccessful treatments will be presented.
Numerical Investigation of Laser Drilling
Authors: Bjorndalen N. , Belhaj H. A. , Agha K. R. , Islam M. R. 
Published: December 2007

Abstract
The need for a new method of drilling oil and gas wells is immense. Current drilling techniques used were developed at the beginning of the last century. Many problems persist with this method including downtime due to dull bits, the lack of precise vertical or horizontal wells and formation fluid leakage during drilling due to the lack of a seal around the hole. Laser drilling is a new technology that has been proposed as a method to eliminate the current problems while drilling and provide a less expensive alternative to conventional methods. Although lasers have found widespread use in many industries, it is only recently that research in this area has been redirected to the oil and gas industry.
A numerical model was developed and verified with previously published experimental data. A detailed parametric study is included and experimental design considerations are discussed. Laser drilling has great potential to revolutionize the oil and gas industry. Design considerations for a field application are presented, with discussion on economical and environmental impacts.
Liaohe Extra-Heavy Crude Oil Underground Aquathermolytic Treatments Using Catalyst and Hydrogen Donors under Steam Injection Conditions
Authors: Zhong L. G. , Liu Y. J. , Fan H. F. , Jiang S. J. 
Published: December 2007

Abstract
The aquathermolysis of Liaohe heavy oil is described which involves the addition of catalyst and hydrogen donors under steam injection conditions. The laboratory aquathermolytic experiments were carried out with the heavy oil, water, catalysts, and hydrogen donors at different temperature (160~260°C) and reaction time (24~240 hours). It was found that the metal species could catalyze the aquathermolytic reactions of Liaohe extra-heavy oil, for example, Fe(II) led to near 60% decrease in viscosity of treated oil at 240°C till 72 hours. However, using catalyst and hydrogen donor (tetralin), more decrease (up to 90%) in viscosity was observed, it indicated the synergetic effect of hydrogen donor and catalyst on aquathermolysis. Average molecular weight, element and SARA analysis showed the same synergetic effect. A cheaper hydrogen donor almost as effective as tetralin was developed from coal tar. The field aquathermolytic testing using catalyst and hydrogen donor were carried out at five Liaohe extra-heavy oil wells, as a result, the oil recovery was improved and treated oil upgraded greatly.
A Procedure for Upscaling Two-Phase Flow in 2D Heterogeneous porous Media
Authors: Virnovsky G. A. , Kløv T. , Øren P. E. , Stensen J. Å. , Lerdahl T. R. , Berge L. I. , Kleppe H. 
Published: December 2007

Abstract
In order to model a WAG process in a North Sea oil field integrated pore-to-field scale multiphase upscaling was performed[1]. The upscaling procedure included two steps. A pore-to-core upscaling step was based on pore network modeling. It resulted in relative permeabilities and capillary pressure functions, which represent the Darcy-scale properties of rock types. The saturation functions were utilized in the next upscaling step.
In this paper we describe the second upscaling step, from centimeters to meters scale, which was performed to derive multi-phase flow functions for the field-scale simulation. This step takes into account heterogeneity of the facies as well as gravity effects, and is based on steady-state upscaling technique. The upscaled flow functions resulting from the second step depend both on the flow direction and on the flow rate (or pressure gradient). The rate sensitivity of the upscaled functions is different for the two directions, horizontal and vertical. The upscaled flow functions in the horizontal direction are rate insensitive, while the vertical flow functions appear to be quite sensitive to the vertical rate.
Derivation, analysis and validation of the upscaled flow functions are described. The latter is done by comparison of the fine grid simulation and homogenized coarse grid simulation in 2D, vertical crossection, and also by comparison of the predicted oil production with field observations.
Can We Ignore Asphaltene in a Gas Injection Project for Light-Oils?
Authors: Sarma Hemanta K. 
Published: December 2007

Abstract
When light-oil reservoirs are considered for miscible gas injection processes (with CO2 or hydrocarbon gases), more often the potential of asphaltene precipitation is either overlooked or not anticipated for two seemingly compelling reasons: first, the asphaltene content in most light-oil reservoirs where gas injection is implemented could be minute, and second, the reservoir has had no prior experience of asphaltene precipitation during its primary production phase. As a consequence, the potential of asphaltene precipitation occurring during gas injection does not get the careful attention it deserves. Operators are often confounded and taken by surprise when they experience a manifestation of serious asphaltene precipitation soon after the gas injection starts. Once the asphaltene precipitation occurs, it causes severe permeability reduction and wettability alteration in the reservoir, and plugging in the wellbore and surface facilities. Remedial measures, which are expensive and disruptive, usually include chemical treatments and workover operations are often disruptive and expensive. Therefore, one must investigate the possibility of asphaltene precipitation prior to implementing a gas injection scheme.
Radical Approach to Water Injection Scheme for Barton
Authors: Sathyamoorthy S. , Priyandoko P. , Flatval K. B. , Bulang A. , van den Hoek P. J. , Qiu Y. 
Published: December 2007

Abstract
Fractured injection is not new to the oil and gas industry, and occurs unintentionally in most water injection schemes. However, deliberate fractured water injection is usually not evaluated upfront in order to derive optimal cost and recovery, and open-up opportunities for further optimization. The initial design for water flooding in Barton was based on a full-blown conventional water treatment plant on a new platform for seawater injection under matrix conditions.
Fracture simulation work revealed that in the case of Barton, by relaxing water quality induced fractures are not expected to be excessively large and cause any concerns on integrity of the reservoir and nearby wells. Owing to a lower required injection tubing head pressure than previously believed to achieve fractured injection only relatively low pressure and cheap injection pumps are required. Additionally, fractured water injection has allowed for the introduction of raw-seawater injection, whereby the significantly smaller water treatment facility than previously required for matrix injection is placed on a deck extension from an existing platform.
Characterizing Partially Fractured Reservoirs by Tracer Injection
Authors: Qasem Fuad , Gharbi Ridha B.C. , Mir Muhammed I. 
Published: December 2007

Abstract
There is considerable interest in the petroleum industry to characterize partially fractured reservoirs and to develop an increased understanding of the physics of fluid flow in these types of reservoirs. This is because fractured reservoirs have different behavior and there exist a large number of these reservoirs that are not fully developed. This paper presents a numerical simulation study that was performed to investigate the effect of rock properties on the tracer response in partially fractured reservoirs using a finite difference numerical simulator. These properties include fracture intensity, fracture porosity and matrix permeability. The functional relationships between these parameters and the calculated effective permeabilities are also investigated. Several images, each with different probability of fracture intensity, were generated randomly. Numerical simulations of single-phase tracer transport were then performed in each of the generated fractured models. Results show that the fracture intensity, fracture porosity and matrix permeability have a significant effect on the tracer response in naturally fractured reservoirs. Depending on the reservoir properties, the results also show that the flow in partially fractured reservoirs can be either matrix-dominated or fracture-dominated. The characteristics of each regime and the conditions for its occurrence are presented.
A New Method to Characterize the Size and Shape Dynamics of Asphaltene Deposition Process in CO2 Miscible Flooding
Authors: Fisher Douglas , Yazawa Nintoku , Sarma Hemanta , Girard Marcel , Turta Alex , Huang Haibo 
Published: December 2007

Abstract
The use of miscible solvents in Improved Oil Recovery (IOR) processes requires knowledge of how the solvent will behave over all mixing ratios of oil and solvent. In particular it is important to know: (i) at what solvent concentration the asphaltenes start to precipitate, and (ii) what conditions will cause the particles to flocculate and eventually deposit in the reservoir pore network. In order to study this process we have developed a new method of describing the process of asphaltene precipitation/flocculation/deposition under typical reservoir conditions.
This method uses image analysis to convert the information obtained from a typical sequence of images obtained from a dynamic high pressure mixing system acquired using a Micro-Visual cell and special optics. These images are analyzed and a single number per image is computed. This number is defined as the "Particle Growth Factor" (PGF), which is a compound number that includes information about the size of the particles, the number of particles and their shape.
This new approach shows how PGF increases with respect to solvent concentration. If we use a suitable non-linear model to fit PGF with respect to concentration, we can use the characteristics of the function to predict the onset of precipitation, the point of maximum flocculation, and when deposition is at its maximum. We can then produce a least squares correlation, which relates the concentration of asphaltene precipitation onset to both pressure and temperature, using a 3D polynomial surface.
In the field, this information can then be used to predict production/injection performance and different operational problems related to asphaltene deposition in CO2 miscible injection and also CO2 sequestration process in a depleted oil reservoir.
Characteristics and Impact of Asphaltene Precipitation During CO2 Injection in Sandstone and Carbonate Cores: An Investigative Analysis Through Laboratory Tests and Compositional Simulation
Authors: Takahashi Satoru , Hayashi Yoshihisa , Takahashi Shunya , Yazawa Nintoku , Sarma Hemanta 
Published: December 2007

AbstractCharacteristics and impact of asphaltene precipitation during CO2 injection are investigated for a Middle East crude oil in both sandstone and carbonate cores through phase behavior studies, corefloods and analyses of the deposition process using a compositional simulator. In phase behavior studies, a light-scattering technique with near infrared was used to determine the onset pressure of asphaltene precipitation. Also investigated were the effects of CO2 concentration on precipitation, including the potential for precipitation by CO2 at the current reservoir pressure.The coreflood tests were conducted above the minimum miscibility pressure (MMP) in both carbonate and sandstone cores to investigate any difference in asphaltene precipitation characteristics in them. The asphaltene content in the produced oil decreased after the CO2 breakthrough –- an indication of its precipitation within the core. A careful post-test analysis of the flooded cores revealed that a larger amount of asphaltene was left behind in carbonate cores than sandstone core.A compositional simulation study with tuned EoS parameters was carried out to evaluate coreflood results, followed by a parametric sensitivity analysis. In addition, the effects of rock heterogeneities on the oil recovery and asphaltene precipitation were investigated. A good match with the oil recovery was obtained. Results indicate that higher the degree of heterogeneities, the higher is the asphaltene accumulation in the core.
Field Application of a New In-Depth Waterflood Conformance Improvement Tool
Authors: Pritchett James , Frampton Harry , Brinkman Joe , Cheung Steve , Morgan Jim , Chang K. T. , Williams Dennis , Goodgame James 
Published: December 2007

Abstract
An Industry Consortium (BP, ChevronTexaco and Ondeo Nalco Energy Services) conducted a multi-company research project known as Bright Water. The goal of this project was to develop a time-delayed, highly expandable material that would improve the sweep efficiency of a water flood.
In November 2001, the first of these water flood profile modification treatments was pumped in the Minas field. The Minas Field, located on the island of Sumatra in Indonesia, has an OOIP of 8.7 billion barrels, is at nearly 50% recovery, and has water-cuts greater than 97%. Reservoir thief zones have been identified throughout the main reservoir layers. The main objective for pumping a profile modification material is usually to divert injected water out of thief zones and into zones with higher oil saturation, though areal sweep improvement can also be expected.
The profile modification treatment of 42,000 barrels water containing 4500 ppm of active material was pumped into Minas injector 7E-12 ("A1" sand). The objective of the field trial was to verify that significant volumes of this low cost material could be pumped deep into the reservoir at low viscosity, and then expand after a pre-designed time interval. Injection tracer studies were conducted pre- and post-treatment to aid in determining changes to the injection sweep efficiency. A bottom hole pressure fall off test was also used to measure post – job permeability.
The trial demonstrated that large volumes of the material can be pumped into the formation without raising the injection pressure or blocking the injection well bore, can propagate in the rock pore system, and then will expand at a pre-designed time. Changes in oil production after the trial will be discussed along with the field data acquired during and after the trial.
As part of the continued development of this material, a second trial commenced in late November 2002 on a North Sea (UK) production platform. The treatment was successfully placed in mid December, 2002.
Assessment of Three-Phase Relative Permeability Models Using Laboratory Hysteresis Data
Authors: Element D. J. , Masters J. H. K. , Sargent N. C. , Jayasekera A. J. , Goodyear S. G. 
Published: December 2007

AbstractGas injection techniques, such as WAG, frequently require consideration of co-existing oil, gas and water phases and the impact of saturation cycles as water and gas slugs move through the reservoir. These processes may be assessed using numerical simulations. This paper presents the analysis of a detailed laboratory study, designed to provide data for verifying hysteresis models for such simulations.A number of studies have reported evidence for hysteresis in gas relative permeabilities in WAG flooding, leading to lower gas mobilities than predicted by conventional two-phase models. A reduction in gas mobility tends to improve gas sweep and incremental recovery for WAG based IOR schemes.Three-phase hysteresis models have recently been developed to include these hysteresis effects. The models include trapping of gas and reduction of water relative permeability in the presence of trapped gas. In these models, saturation changes can be irreversible, and relative permeability may decrease with each change in direction in saturation.A carefully planned laboratory study investigated secondary and tertiary immiscible WAG floods in both water-wet and intermediate-wet Berea cores, giving four separate sets of experimental data (a total of over 30 individual floods). For each flood, in-situ saturation profiles, mass balance and pressure drop data were measured. The in-situ saturation data ensures that laboratory artefacts (such as capillary end effects) do not influence conclusions.Analysis of the experimental data shows that hysteresis models should include the following features: –Irreversibility of hysteresis cycles;–Potential for the reduction in the residual oil saturation with trapping of gas by water;–Reduction in both water and gas permeability, with potential for the fractional flow to vary with trapped gas saturation;–Variation in Land trapping factor between hysteresis cycles.This study confirms the need for three-phase hysteresis models. Although published models may include some of the observed hysteresis effects, no model includes them all.