bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated Workflow for Modeling Basin-Scale Petroleum Systems: Applications to the Kupe Area, Taranaki, New Zealand
Authors: Roncaglia L. , Arnot M. , Baur J. , Fohrmann M. , King P. , Kroeger K. F. , Ilg B. , Strogen D. , Zhu H. , Milner M. 
Published: February 2011

Abstract
This paper describes a multidisciplinary integrated workflow for mapping Late Cretaceous to Recent subsurface structure and stratigraphy, and modeling petroleum systems of the Taranaki Basin (74,209 km2), New Zealand. The basin-scale assessment of geology and fluid flow is aimed to improve previous, mostly local, studies. The size of the study area and integration over a nine-year timeframe of large datasets, multiple software and disciplines present technical challenges.
The workflow consists of the following six main tasks: data compilation, quality assessment and integration; structural and stratigraphic interpretation of seismic reflection data over a regional framework and local grids including assessment of timing and volumetrics of erosion; validation of the geometric and geological integrity of the structural framework through structural restoration; seismic attribute analysis and facies mapping to constrain the sedimentary facies distribution and the paleogeographic evolution of the basin; construction of 3D static models of stratigraphy, lithology distribution and faulting, as determined from the seismic and well interpretations; development of 4D dynamic models of basin deformation and petroleum generation and migration through time, to improve prediction of where as-yet undiscovered petroleum accumulations may be preserved.
Representative examples of data applications and results are presented for the hydrocarbon-producing Kupe area (4,155 km2). In Kupe, more than 200 fault planes and 20 laterally-continuous stratigraphic horizons are mapped, constrained by well data, and included in structurally-validated 3D framework models, which are populated with seismic attribute properties. The 4D models are created by integrating the results of all the steps of the workflow with source rock geochemical properties, heat-flow data from crustal-scale modeling, and rock properties for reservoir fairways.
This integrated workflow and associated data management and interpretation protocols have proved effective for developing a holistic 4D depiction of Taranaki Basin tectono-stratigraphy and petroleum systems. It provides a co-ordinated approach to interrogating large amounts of independent data, and the derivative models are the base for detailed petroleum exploration. Lessons learned may serve as guidelines for projects of similar scale.
A Model of the Impacts of Operational Risk and Analysis of Hedging Strategy with Derivatives for Oil Producing Companies
Authors: Carvalho M. H. , Lima G. A. , Ravagnani A. T. , Schiozer D. J. 
Published: February 2011

Abstract
Economist and finance professionals are always concerned with risk in variables like NPV, IRR, payback, ROA, ROE and other indicators used by analysts and management team. But, in the day-by-day, discussions about risk in operational availability, loss of production, concern of failure of equipment on production, environmental impacts, damage due to hurricane and storms, among others. Currently, operational risk is not so discussed in the oil industry as financial risk, but it may cost billion to insurers and oil companies in events like Katrina, Ike and others.
In this paper, the operational risk of an oil project, its impacts and ways of protection to reduce exposure are studied. The approach is composed of the following:
Macro-modeling of the reliability and operational risk of the oil production system (platform, pipes etc.); Simulation of reliability, availability, downing events etc. over a period of interest (usually, 20 years); Estimation of loss of production and its associated cost with failure of equipments; Use of financial derivatives to hedge loss due to operational risk.
This model is applied to an oil production project similar to those ones of the Brazilian offshore basins. We find that derivatives could be a direct way to hedge oil companies against loss, using financial instrument already traded in the market at a very competitive price, when compared to a traditional insurance policy.
Integrating Reservoir Characterization: 3D Dynamic, Petrophysical and Geological Description of Reservoir Facies
Authors: Knackstedt Mark , Jaime Patricio , Butcher Alan R , Botha Pieter WSK , Middleton Jill , Sok Rob 
Published: February 2011

Abstract
Integrating conventional geologic, petrophysical and reservoir engineering rock typing methods requires studies which incorporate 3D imaging of rock material, 2D petrographic studies, fluid:fluid and fluid:solid interactions (e.g., wettability), and geological facies descriptions. This paper illustrates a new integrated methodology for the multidisciplinary study of reservoir core material. Petrophysical units define zones of a reservoir with similar flow and storage capacity. Geological facies are based on depositional and diagenetic criteria, which are tied to poro-perm data. Empirical relationships are often used to tie the petrophysical to the geological models, to estimate initial hydrocarbons in place. Reservoir engineers also wish to define rock types based on their recovery characteristics (e.g., relative permeability). In this case fluid properties (e.g., fluid components and wettability) can be a major factor controlling the flow and distribution of fluids in porous rocks, which in turn greatly impacts ultimate recovery of hydrocarbons. QEMSCAN®, automated Scanning Electron Microscopy with fully integrated x-ray microanalysis and image analysis, enables one to obtain spatial and numeric 2D mineralogical information from geologic samples. This analysis allows high quality 2D mapping of key parameters used in characterizing rocks: mineralogy, modal mineral proportions, mineral relationships and associations. Micro-CT (μ-CT) imaging enables one to enumerate the porosity, pore geometrical and topological complexities in reservoir rock and visualize fluids within the pore structure of core material in 3D; this enhances the estimation of both fluid flow and recovery properties of core. Results show how the integration of these techniques allows one to more accurately map the mineralogy and wettability characteristics of reservoir rocks in three dimensions, and therefore better couple relevant information from petrologists, petrophysicists and reservoir engineers. A number of case studies illustrate the application of this integrated approach to enhance prediction of petrophysical and multiphase flow characteristics in complex core.
Predicting Effective Permeability to Oil in Sandstone and Carbonate Reservoirs from Well Logging Data
Authors: Anand V. , Freedman R. , Crary S. , Minh Chanh Cao , Terry R. L. 
Published: February 2011

Abstract
This paper discusses a new method for predicting continuous logs of effective permeability to oil in sandstone and carbonate formations from well logging data. This important problem in formation evaluation has remained previously unsolved because the conventional approach used to predict reservoir properties from well log data relies on simple empirical equations and idealized models of reservoir rocks. The use of such equations and models to predict a complex reservoir property such as effective permeability can result in an inaccurate representation of the formation.
This paper shows that accurate values of effective permeability to oil can be predicted using model-independent mapping functions, constructed from Gaussian radial basis functions, which can be derived from a laboratory database of measurements on partially saturated core samples. The mapping functions replace the empirical equations used in the conventional approach and are model-independent representations of the database measurements. Once the mapping functions are constructed from the database there are no adjustable parameters.
In this study, mapping functions for sandstones and carbonates were derived from a worldwide database of laboratory measurements made on 79 sandstone and 25 carbonate core samples. The laboratory measurements available on each sample included irreducible water saturation, effective permeability to oil, porosity, and NMR T2-distributions. The mapping functions can be used to predict effective permeability to oil of reservoirs at irreducible water saturation from input measurements of porosity,T2-distribution, irreducible water saturation, and knowledge of rock lithology, e.g., sandstone or carbonate.
The methodology for deriving the mapping functions is explained in detail. The mapping functions are applied to the database itself to show the accuracy of the effective permeability predictions on core samples. The method is also applied to log data from both sandstone and carbonate formations in three wells from different parts of the world. The predicted effective permeabilities to oil are shown to be consistent with oil mobilities measured in the formations by fluid sampling tools.
Controlling Coal-Fines Production in Massively Cavitated Openhole Coalbed-Methane Wells
Authors: Magill Douglas , Ramurthy Muthukumarappan , Jordan R. , Nguyen Philip 
Published: February 2011

Abstract
In the San Juan basin Fairway, cavitated Fruitland coalbed-methane (CBM) wells have been successfully producing for the past 30 years. However, over the years, coal-fines migration into these cavitated wellbores has resulted in pump issues and coal-fines production, leading to a significant decline in production. To clean out the coal fines and replace the pumps on a continuous basis is a costly workover issue. Hence, a foamed remedial treatment was designed to displace the conductivity-plugging coal fines away from the wellbore and immobilize them with the foam also serving as a diverting agent. This has allowed the production and dewatering process to continue without any interruption. The remedial treatment was chosen because the aqueous tackifier in it can control the fines and help prevent them from plugging the flow path. Also, it dissolves any calcium-carbonate scale in the wellbore and near-wellbore region.
In this study, 15 cavitated wells with coal-fine issues were selected for the foamed remedial treatment. In all of these 15 wells, the coal-fines issues were resolved. This allowed production to be uninterrupted and reduced the cost of workover rigs and pumps. As a secondary benefit, production stabilized in 10 wells and increased in 5 of these wells. This study shows the production results from these two groups of wells that were treated. It also discusses the design options for the treatments and lessons learned from the process. This technology can be applied to openhole as well as cased multilayered CBM wells.
Building on PRMS to Quantify Risk and Uncertainty in Resource Reconciliations
Authors: Etherington John R. , Stabell Charles B. 
Published: February 2011

Abstract
The Petroleum Resources Management System (PRMS) provides a project-based approach to assessing the full range of recoverable quantities in accumulations from early exploration through mature development phases. As new technical information becomes available and/or commercial conditions change, the estimates of recoverable volumes and their associated risk and uncertainty must be updated. The recording of these changes and the contributing factors is termed resource tracking or resource reconciliation.
For publicly traded companies, regulatory agencies define specific change codes. The US Securities and Exchange Commission (SEC) has historically focused on Proved Reserves and registrants reported annual additions (asset purchases, new discoveries and extensions, improved recovery), deletions (production, asset sales) and revisions (technical and commercial-based) to prior year estimates.
Internal systems must apply resource tracking to the company's full portfolio of projects and are more focused on changes to the expected value (mean) of the estimates. The portfolio may include Reserves, Contingent Resources (discovered not commercial), and Prospective Resources (undiscovered). PRMS further defines sub-classes based on project maturity with the option to quantify associated risk (chance of discovery). Moreover, each resource category has an implied associated confidence factor that discounts volumes for uncertainty. For example, only a portion of Possible volumes may ultimately transfer to Proved. These confidence factors (or "uncertainty discount factors") may be estimated through parallel probabilistic analyses or based on analog assessments. Changes in confidence-factor must be considered as an additional revision type regarding transfers between categories.
This paper discusses a quantitative approach wherein companies compute an expected value for each project as the sum of the confidence-weighted category volumes and also apply an associated sub-class risk factor. A realistic example illustrates combining risk/confidence-weighting and qualitative descriptions of the key source of changes in estimates to support both internal and external resource tracking requirements.
Application of Composite Jet-Rod Pumping System in a Deep Heavy-Oil Field in Tarim China
Authors: Shen Jianxin 
Published: February 2011

Abstract
Great challenges had been faced in the design and selection of artificial lift methods at Lungu reservoir of Tarim field in the North West China due to the extremely deep reservoir and extra-viscous crude. The average depth of the reservoir is about 5500m. The initial reservoir temperature is about 127°C, and pressure ranges from 57 to 64 MPa. With very high content of resins and asphaltenes, the oil from this reservoir has a viscosity of about 10×104mPa.s at 50°C and density varying from 0.95 to 1.08 g/cm3. Thanks to the high reservoir temperature along with high pressure, the oil has fairly enough mobility to flow into the well bore under reservoir conditions. However, as it flows towards the surface, the decrease in temperature along the well bore causes dramatic increase of viscosity. Both calculations and field experience suggested that it is not possible to meet the required production rate with only one particular available mechanical lift method, such as rod pump, jet pump, or other individual lifting method.
To overcome the lifting difficulty and achieve the production volume, a composite pumping system which combines both jet and rod pumps was proposed and practiced in this field. The proposed composite jet-rod pumping system was proven to be a great success, which significantly increased and maintained production volume in the wells tested. This paper discusses the working mechanisms involved in the composite jet-rod pumping system, the lifting parameter optimization methodology and workflow, and the field application experience. This composite jet-rod pumping system was demonstrated to be the most promising mechanical lift system for Lungu reservoir and it can be potentially used in the other deep heavy oil fields world wide.
Flow Profiling and Completion Leak Detection with Memory Production and Corrosion Logging Tools in High Profile Gas Condensate Wells: Case History from Southeastern Bolivia
Authors: Foianini Ivo 
Published: February 2011

Abstract
Production logging is a necessity in today’s deep and complex reservoirs, where high-production and extreme downhole conditions (including high pressure high temperature (HPHT), carbon dioxide, and hydrogen sulfide) require constant monitoring of well performance. This service can be combined with other cased hole logs, such as tubing evaluation and pulsed neutron, to establish a customized relationship between the fluid, wellbore, and completion properties. This process enables the construction of an instantaneous relationship between these three elements and determines the efficient production of each well.
This service integration was successfully applied in a deep gas condensate well in southeastern Bolivia. With more than 5200 m of total depth and a wellhead pressure of 5,500 psi, the operating conditions proved to be difficult. However, they proved ideal for the use of memory logging tools that, when deployed downhole with slickline wire, facilitated surface pressure control without risking log quality assurance/quality control (QA/QC).
Producing at a high flow rate (&gt; 100 MMscf/d) from three reservoirs, the well required constant flow profiling and production follow-up. In addition, the presence of carbon dioxide in the gaseous stream provided opportunities for weakening the mechanical integrity of the completion through the onset of corrosional events. After running a production log, the client discovered an unexpected fluid entry point in the completion string, which was confirmed as an orifice with a subsequent tubing evaluation logging run. After reviewing the original production log, the client determined that the high flow rate from a particular formation had eroded a blast joint and created the orifice.
Running these services with memory tools reduced preparation time and operating costs. These benefits enabled the client to quickly acquire detailed information about the downhole condition of the well, improve the understanding of the relationship between reservoir and completion, and reduce production downtime and service costs.
Benefits of Freshman Engineering Projects for Petroleum Engineering Students
Authors: Bryant J. A. , Salama G. H. , Fahes M. M. 
Published: February 2011

Abstract
The engineering program at Texas A&M University includes a freshman "Introduction to Engineering" sequence for the first two semesters of the freshman year. The Qatar campus of Texas A&M University has four majors offered and all majors take this two semester sequence. The overview course covers many subjects for the students and these typically are very broad in scope. Both courses include at least one or several projects.
Each year, freshmen student evaluations are critical of the perceived lack of applicability of the design project to petroleum engineering students. One possible reason for this perception could have been that during the first four years of program startup, there were no petroleum engineering professors involved in teaching this course. Nevertheless we noticed that the projects introduced important skills that petroleum engineers need. A review of the junior and senior curriculum and ABET outcomes confirm this.
In this paper, we discuss some of the projects offered in these freshman courses, and the skills it promotes. We also present the results of a survey that included almost all of the students at Qatar campus from all four engineering majors and compare the responses of the students in terms of the perceived benefits of these courses and the skills it promotes.
Proper design of projects for inclusion of necessary skills and tools for petroleum engineers is recommended to ensure students are equipped with appropriate competencies needed for upper division classes. Our results show that the skills promoted by projects currently being implemented are in line with the skills that petroleum engineering students need for their upper devision classes as well as their careers.
Water Recycling Helps with Sustainability
Authors: Pierce Dale A. , Bertrand Kelly , Vasiliu Cornelia Cretiu 
Published: February 2011

Abstract
The oil business uses a large quantity of water during the drilling and completion of an unconventional gas well. In many of the shale plays each well needs in excess of 4 million gallons of water (100,000 bbl) during the drilling and completions operations. Water is a precious resource and many areas are faced with water shortages.
Water shortages extend to almost all the traditional oil and gas producing areas in the United States including Colorado, California, Wyoming, Texas and Oklahoma. Also, the arid areas of Australia, The Middle East, and Africa see even more severe shortages of fresh water than in the United States. Moreover, in areas where water is not in short supply such as Indonesia, Malaysia, and the Eastern United States, discharge of high salt content water is problematic. In order to assure itself of adequate water for drilling and completion operations, the oil business needs to change the ways it has traditionally transacted its business.
As stated above many drilling areas are faced with water shortages, whereas many other producing areas are faced with high disposal costs for frac flow back water and produced water. In many traditional production areas disposal of water is simple and usually inexpensive since there are numerous injection wells in these traditional production areas. However, in some of the new Shale plays the access to injection wells for disposal of produced water and frac flow back water is very limited.
Part of the solution is to recycle the frac flow back water and the produced water for use as drilling fluid or for Frac Fluid. How clean does this water need to be for use as a drilling fluid or a frac fluid? What techniques are used to clean this water? How costly are the various techniques? These questions and others will be addressed in this paper.
Increasing Lazy Gas Well Production: A Field Wide Case History in Northern Alberta
Authors: Wylde J. J. 
Published: February 2011

Abstract
This paper summarizes methods, chemistries, and application results for a range of liquid foaming agents on a collection of wells applied at a single property in Northern Alberta. The paper goes on to summarize the philosophy, design criteria for selection of remediation chemistries, and methodologies used to counter the production decline occurring as a result of water production.
Gas flow rates from these low pressure gas wells were being dramatically affected by production of free or condensed water. If allowed to collect to sufficient levels, the produced fluid killed production altogether. The shallow (500 to 750 meters) wells on this lease are particularly sensitive to fluid production as reservoir pressure was very low, approximately 700 kPa (102 psi), and production of only 0.5 m3 (3.15 bbl) of water per day could kill a well.
Additional challenges were caused by high solids production and scale deposition. Additionally, further loading up the wells and lowering production as well as asphaltene precipitation, formed a very adherent and dense solid precipitate with sand produced by the well.
Initially wells were cleaned with a combination batch asphaltene solvent. Subsequently, a very pervasive foam forming chemical was used to unload solids. Continuous injection of 2 liters per day of a liquid based foaming chemical into one particular well increased gas production by 3 e3m3 (0.1 mmcf) per day (a 50% increase). Other wells were successfully treated to remove water and solids that were blocking the perforated interval. Significant value was added by increasing production field wide by 33% with an insignificant associated chemical cost.
The results and conclusions of this work are applicable to the shale gas and CBM fields being produced throughout North America and enable best practice chemical well enhancement to be applied.