bluuebunny/crossref_metadata_2025_split huggingface dataset:
Predicting Openhole Horizontal Completion Success on the North Slope of Alaska
Authors: Erwin M. D. , Ogbe D. O. 
Published: December 2007

Abstract
The Colville River Field (Alpine) represents the first widespread and successful application of openhole horizontal completions on the North Slope of Alaska, and one of the first in the world. The purpose of this paper is to examine why this completion technique was selected and identify the key parameters that favored its successful application in the Colville River Field. The optimal completion technique for a candidate well is determined by the reservoir properties, geologic setting, rock mechanics, development plan and completion design. In this paper we will review the unique advantages and disadvantages of openhole horizontal completions based on the Colville River Field.
From the results of the review, three key parameters were found to be critical to the success of openhole horizontal well completions and should be applied broadly in other situations. Using these three key parameters as criteria, other major North Slope reservoirs are evaluated to determine their potential for openhole horizontal completion applications. Focus areas in this evaluation include in-situ reservoir parameters, development plans, fluid contacts, and wellbore geometries. The results showed that only one other major field on the North Slope could have benefited from openhole completions.
The results of this paper are meant to provide guidelines for the future application of openhole horizontal completions both on the North Slope of Alaska and beyond.
Proppant Flowback Prevention—A New Technology for Low BHST Applications
Authors: Johnson D. E. , McWilliams J. L. , Nelson S. G. , Blount J. S. 
Published: December 2007

Abstract
A new phenolic resin system has been developed for proppant consolidation when fracturing low temperature wells. Before the development of this new resin system, which was in response to a global industry need, external chemical activators were necessary to achieve sufficient bond strength of the resin coated sand pack (when treating wells with bottom-hole temperatures less than 140°F). This new low-temperature cure system develops superior proppant pack bond strength and requires no external activation at temperatures as low as 100°F. Eliminating the need for external activators not only decreases the complexity of the fracturing treatment, but also contributes to the saving of time, money, and decreases the need for chemical transportation and the associated potential hazards. However, the lower operating temperature limit of this resin chemistry can be extended even further with the addition of an external chemical activator.
The paper will discuss product performance data that was generated to document the effectiveness of this technology at simulated downhole conditions. Results from the initial field trials utilizing the new Low Temperature Resin Coated Curable Proppant (LTRCCP) in various shallow wells in the Permian Basin will also be presented. Field trial data resulted from thirty-nine treatments that were performed on a total of twenty-two wells, in nine different producing horizons, spread over four different fields in Southeast New Mexico and West Texas. The Information presented describes formation properties, treatment designs, post fracturing production response and lessons learned.
A Neurosimulation Tool for Predicting Performance in Enhanced Coalbed Methane and CO2 Sequestration Projects
Authors: Gorucu F. B. , Ertekin T. , Bromhal G. S. , Smith D. H. , Sams W. N. , Jikich S. A. 
Published: December 2007

Abstract
One of the more important environmental issues is the increase in atmospheric carbon dioxide (CO2) concentration resulting from anthropogenic sources. The CO2 sequestration process includes capturing, separation and storage of carbon dioxide, and targets a potential solution mitigating the amount of CO2 in the atmosphere. This work focuses on the last component of the aforementioned sequestration process, storage of CO2. Coal seams are chosen as potential repositories because there are several advantages where the sequestration costs can be offset in various ways.
The purpose of this study is to develop a tool for the practicing engineer to predict the important performance indicators that are critical in CO2 storage projects in coal seams. The neuro-simulation methodology coupling the hard computing protocols with the soft computing protocols is used. PSU-COALCOMP, a compositional coalbed methane reservoir simulator (hard computing protocol), is used to generate the necessary training data sets utilized in the training of the artificial neural networks (soft computing protocol) that are developed in this study. The tested neural network predictions are found to be accurate and sufficiently precise to establish confidence in the tool. Accordingly, the developed neural network can be used to screen thousands of possible scenarios of operational conditions in the optimization of the coal sequestration project design parameters in few seconds without going through intensive numerical simulations.
Multidimensional Velocity-Based Model of Formation Permeability Damage: Validation, Damage Characterization, and Field Application
Authors: Mojarad R. S. , Settari A. 
Published: December 2007

Abstract
The loss of injectivity in produced water and seawater injectors due to formation plugging is well documented in the literature. Reliable modeling of the permeability loss is the key to the analysis of field data and to design and economics of projects.
Standard formulation of damage mechanics is based on the classical deep bed filtration (concentration-based) model, which requires two parameters: filtration coefficient λ and formation damage coefficient β. Determinationof these paramteters is expensive and difficult. Moreover, the model is not easily implemented in reservoir simulators.
This paper presents an alternative approach to modeling damage based on the formulation proposed by Bachman et al. (SPE 79695). The numerical implementation and validation of this empirical, velocity-based model is extended to two dimensions. The model was extended to 2-D flow and validated by a comparison with the deep bed filtration model. The velocity model gives remarkably accurate approximation to the more complex concentration model. Unique relation between the parameters of the two models was found, and used to develop a new methodology to characterize damage by matching lab or field data.
Application of the model to the published data from offshore Gulf of Mexico is presented. The velocity method allows more accurate history matching and the damage characterization by history matching yields parameters close to those measured.
Openhole vs. Cased-Hole Hydraulic Fracturing
Authors: Gottschling J. C. 
Published: December 2007

Proposal
An open-hole hydraulic fracturing (OHF) process has evolved to economically treat low pressure and low quality upper Devonian sands in western Pennsylvania.
In order to evaluate the effectiveness of the OHF process, a study was done to chronicle, investigate and postulate about the OHF process. This study used well data from two particular fields in western Pennsylvania. Data from Field #1 was used to provide OHF and offsetting cased-hole production data. Field #2 was the source for all mini frac analyses plus additional producion data. The study focus involved several integral parts.
Understanding of the geology typical to the areas where the OHF process was common was accomplished by referencing the ample amount of published data on the upper Devonian sands in western Pennsylvania. Additional information was incorporated from recent core studies.
Creating a chronicle of the OHF process involved a detailed step-by-step description of the process along with pressure analyses to determine created fracture geometry and reservoir permeability. Breakdown data from 160 OHF stages was analyzed in an attempt to predict the production potential of a zone.
The final segment of this study was an overall comparison of the OHF and cased-hole stimulated wells. Expenditures for drilling, completion were included in the analysis. IP's, 3 month, 6 month and 1 year cumulative MCF's were used in the evaluation.
From Geological Knowledge to Good Decisions Using Simple Stochastic Models: A North Sea Case Study
Authors: Hollund K. , Hauge R. , Syversveen A. R. , Jørstad A. , Lie T. , Rønnevik H. C. 
Published: December 2007

Abstract
The decision process for one of the partners in the development of the Alvheim field is presented. The challenge was to turn relatively small Palaeocene structures consisting of both unproven prospects and proven oil and gas reserves into a field development with a good economic performance. The paper describes the stochastic model that was buildt to support decisions in the early phases of the field development.
To pinpoint the essential elements for a model is difficult task. Not only the characteristics of the field, but also the decisions that the model is supposed to support, must be considered. A simple stochastic model was buildt. An exploration type of approach was used. Essential elements are volume-depth curves and modeling of seismic uncertainty and uncertainty in fluid contacts.
Using the model, it was possible to explore important upside potensial seen in geophysical evaluations and answer if and in what sequence further wells should be drilled. An improved understanding of the value for different drilling strategies was gained by studying distributions for in-place oil and gas volumes for various scenarios.
Horizontal-Well Productivity Equations With Both Uniform-Flux and Uniform-Pressure Wellbore Modes
Authors: Chen H. -Y. , Asaad N. 
Published: December 2007

Abstract
This paper concerns the estimation of pseudosteady-state horizontal-well productivity with emphasis on handling two types of wellbore conditions: uniform-flux and uniform-pressure. We present rigorous (analytically) and simplified PI (productivity index) equations which can easily handle the above two wellbore conditions within a consistent framework.
The presented simplified PI equations were verified successfully (i) through detailed mathematical/physical analyses, and (ii) against the more rigorous solutions and published examples, for wide ranges of drainage shape, permeability anisotropy, and well length.
Fluid Characterization for Miscible EOR Projects and CO2 Sequestration
Authors: Jessen K. , Stenby E. H. 
Published: December 2007

Abstract
Accurate performance prediction for miscible EOR projects or CO2 sequestration in depleted oil and gas reservoirs relies in part on the ability of an equation of state (EOS) model to adequately represent the properties of a wide range of mixtures of the resident fluid and the injected fluid(s). The range of mixtures that forms when gas displaces oil in a porous medium will, in many cases, differ significantly from compositions created in swelling tests and other standard PVT experiments. Multicontact experiments, e.g. slimtube displacements, are often used for the conditioning of EOS models applied in performance evaluation of miscible displacements. However, no clear understanding exists of the impact on the resultant accuracy of the selected characterization procedure when the fluid description is subsequently included in reservoir simulation.
In this paper we present a detailed analysis of the quality of two different characterization procedures over a broad range of reservoir fluids (13 samples) for which experimental swelling tests and multicontact data (slimtube experiments) are available. We explore the impact of including swelling test and multicontact data in the data reduction. We demonstrate that swelling tests, in some gas/oil systems, do not contribute to more accurate predictions of multicontact miscibility. Finally, we report on the impact of using EOS models based on different characterization procedures on recovery predictions from dynamic 1D displacement calculations.
Multicontact Miscible Flooding in a High-Pressure Quarter Five-Spot Model
Authors: Dao E. K. , Lewis E. , Mohanty K. K. 
Published: December 2007

Abstract
Miscible and near-miscible gasflooding has proven to be one of the few cost effective enhanced oil recovery techniques. The sweep efficiency of such processes is often not high due to adverse mobility ratio, gravity override and reservoir heterogeneity. Several sweep improvement techniques have been developed, but there is no laboratory technique to estimate sweep efficiency at reservoir conditions. A high-pressure quarter 5-spot cell has been constructed in this work to conduct multicontact miscible water-alternating-gas (WAG) displacements at reservoir conditions. Multicontact miscible solvents are identified by conducting slimtube experiments for a medium viscosity oil (78 cp). Coreflood experiments are conducted to determine microscopic displacement efficiency as a function of WAG ratio. Quarter 5-spot experiments are conducted to infer sweep efficiency in a 3D geometry at the laboratory scale. WAG improves the microscopic displacement efficiency over continuous gas injection followed by waterflood in corefloods. WAG injection improves the oil recovery and thus sweep efficiency in the quarter 5-spot model over the continuous gas injection followed by waterflood. WAG injection slows down gas breakthrough. A decrease in the slug size improves the sweep in WAG floods. Use of a horizontal production well lowers the sweep over a vertical production well during continuous gas injection.
Fracture-Optimized Production Efficiently Stimulates Sandstone Formations With Dunvegan Formation: Case Study
Authors: Leshchyshyn T. T. , Thomson J. D. 
Published: December 2007

Abstract
In the Western Canadian Sedimentary Basin (WCSB), fracturing stimulations have been done for 70 years. In Canada, the government, service companies, and well operators accumulate massive volumes of information. This information exists in the form of paper files and databases of varying detail containing well and treatment information. The information age makes production data available making another leap in determining fracture designs based on real production results of past treatments.
In the past few decades, a common way operators started the design process was to approach service companies for their experience in an area and formation. From around 1955, many new designs were created by referring to old designs. Then the industry used designs that were pumped in the field which progressed in later years to stimulation that were pumped to completion. This sometimes progressed to job designs pumped with production from the stimulated formation. More value is attained by looking at optimal post fracture production using actual results not calculated, uncalibrated predictions. This is most powerful when the production results are matched to calibrated fracture models, reservoir models and petrophysical analysis to continue area projects in stimulated a formation.
This case study covers 3,600 square miles from 58-19W5 to 68-02W6 of the Dunvegan formation. It is a tight, water sensitive formation usually producing gas. Geologically, the Dunvegan has less than 1 mD permeability. The success of various fracturing techniques are evaluated on several levels including a review of the 203 out of the 406 wells in the region. The fracturing strategy comparisons will evaluate base fluid selection, proppant type, and the amount of proppant. The current commodity prices are used to calculate the optimized results versus the vast amount of information that was collected in the past using lower prices.
Hydrocarbon based fracturing fluids were used 85% of the time as one would expect based on the geological evaluation of the area. However, the infrequent and larger water fractures have an IP rate of 1.5 MMscf/day using 100,000 lb of proppant where the more frequent and smaller hydrocarbon fractures are 1.2 MMscf/day using 40,0 lb. Total recovered gas is 4 times higher for the water fractures compared to the hydrocarbon based fractures. The optimization of the hydrocarbon fractures with respect to the pounds of proppant used will also be examined since the most common size was 33,000 lb but was found to have optimal IP gas production using 66,000 lb.
An Integration of Multilevel Local-Global Upscaling With Grid Adaptivity
Authors: Lambers J. , Gerritsen M. 
Published: December 2007

Abstract
We present an iterative method for generating appropriate coarse scale models for adaptive flow simulation in highly heterogeneous reservoir formations. Our approach applies to any strategy for generating structured adaptive grids, but we will focus on Cartesian Cell-based Anisotropic Refinement (CCAR) grids due to their suitability for EOR processes that require aggressive refinement.
We first construct an initial grid that captures the principal flow paths in the reservoir. Refinement is driven by regions of greater heterogeneity in the fine-scale permeability field, which are detected using a connected set approach1. Next, we generate a hierarchy of coarse-scale permeability fields, beginning with the finest scale on the simulation grid. Each field is computed using a local-global upscaling approach2, which employs generic global coarse scale simulations to determine the boundary conditions for the local calculation of upscaled transmissibilities or diagonal permeability tensors. An iteration procedure assures consistency between the local and global calculations. As we proceed to coarser scales, permeability values at finer scales are fixed in order to ensure that fine-scale high permeability flow paths are preserved. This is especially important when simulating gas injection processes because the highly mobile gas will preferentially flow through these paths. Thus we obtain a permeability field that yields an accurate global flow solution with sufficient local resolution where required. Adaptivity eliminates the need to represent permeability with full tensors; diagonal tensors are sufficient.
Furthermore, the combination of adaptivity determined by the connected set approach, and the local-global upscaling (which introduces global connectivities) leads to accurate representation of potential flow paths. Because of this, we significantly reduce process dependency.
For highly heterogeneous (e.g., channelized) systems, this new approach is shown to consistently provide more accurate coarse scale models for global flow in a variety of directions, relative to reference fine scale results, than do existing local, extended local, or local-global upscaling techniques applied to uniform grids.
Next Generation Expandable Completion Systems
Authors: Innes G. , Morgan Q. , Macarthur A. , Green A. 
Published: December 2007

Abstract
This paper documents an 18-month expandable technology research and development effort that has culminated in a system that enables a new approach to reservoir architecture.
The drive for maximum well productivity compels oil and gas companies to consider openhole completion strategies. However, historical uptake has been impeded by inability to achieve effective zonal isolation. The Expandable Reservoir Completion [ERC] combines slotted and solid expandable technology and features a return to conventional unexpanded premium connections to deliver a freely configurable reservoir completion architecture, offering a combination of openhole production performance and cased hole functionality.
Fundamental to the new Expandable Reservoir Completion is a unique, selective rotary compliant expansion technique, which is used to clad the formation wall with expandable screens, slotted liner or solid tubulars with sealing units. This technique facilitates unparalleled flexibility in reservoir design by allowing sections of conventional casing to remain unexpanded between zones. This enables integration with conventional flow control and intelligent completion equipment, ultimately permitting selective isolation & production control.
This paper outlines detailed test data generated by the development program, which included three downhole field trial installations. In addition to this, information from the first global commercial installations will be presented, from pre-job planning through to post installation performance review.
The Expandable Reservoir Completion builds upon existing expandable sand screen and solid expandable technologies to deliver a combination of productivity and functionality previously unavailable to the petroleum industry.
Continuing Education Needs for the Digital Oil Fields of the Future
Authors: Ershaghi I. , Omoregie Z. 
Published: December 2007

Abstract
The increasing demand for cost effective development of oil and gas resources in harsh environments and the need to squeeze more reserves from mature fields have led to an industry-wide push to develop the framework for the digital oilfields of the future1 (called by different names in the industry: "smart fields", "i-field", "efield", "digital oil field of the future", or DOFF,.. etc). Over the past few decades, the world has seen tremendous leaps in the development of hardware and software tools that measure, analyze and optimize process systems. The cost of these tools has continued to decrease. The increased infusion of these technologies in oil and gas asset management has helped many to see greater benefits from making fundamental changes in the infrastructure used to develop oil and gas fields and the work tools and processes used to manage them. Currently available technologies already allow oil and gas professionals to work in a more collaborative environment than ever before. As the industry focuses on developing the technologies required to implement the digital oilfield of the future, the industry must also, simultaneously, focus on the training and recruiting of the manpower qualified to operate digital oilfields. Continuing education must include elements that can provide the practicing professionals with the tools needed to manage the digital oilfield of the future. For students aspiring to join the industry, academia needs to prepare them to manage oil and gas assets with tools and work processes different from what are used today.