bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cased Hole Exploration and Recompletions in West Texas Based on the Continuous Carbon/Oxygen (C/O) Log
Authors: Flynn J. , Conley S. , Frost E. , Fertl W. H. 
Published: December 2007

ABSTRACT
Recent field experiences in West Texas with the Continuous Carbon/Oxygen (C/O) Log illustrate the potential of this cased hole logging service to assist in the re-evaluation of partially depleted oil reserves and exploration for by-passed oil in old wells in mature, producing areas.
Interpretive concepts and possible pitfalls are outlined for quick-look evaluation at the wellsite and detailed computerized analysis. Field case examples, including the results of subsequent production tests in the Yates, Seven Rivers, Queen, Grayburg, San Andres, Glorieta, and Clearfork formations illustrate successful applications of the C/O Log in West Texas.
Thermal Techniques for the Recovery of Heavy Oil and Bitumen
Authors: Nasr T. N. , Ayodele O. R. 
Published: December 2007

Abstract
Over 90% of the world's heavy oil and bitumen (oil sands) are deposited in Canada and Venezuela. Alberta holds the world's largest reserves of bitumen and the reserves are of the same order of magnitude as reserves of conventional oil in Saudi Arabia. Up to 80% of estimated reserves could be recovered by in-situ thermal operation. As the resources available for conventional crude in Canada continue to decline, further development of heavy oil and oil sands in-situ recovery technologies is critical to meeting Canada's present and future energy requirements.
Sophisticated technologies have been required to economically develop Canada's complex and varying oil fields. Various existing in-situ technologies such as hot water injection, steam flooding, cyclic steaming and combustion processes have been successfully applied in Venezuela and California. Most recently, advances made in directional drilling and measuring while drilling (MWD) technologies have facilitated development of new in-situ production technologies such as the steam assisted gravity drainage (SAGD), expanding solvent-SAGD (ES-SAGD) and solvent vapor extraction (VAPEX) that have significantly improved well-bore reservoir contact, sweep efficiencies, produced oil rates and reduced production costs.
This paper provides an overview of existing and new thermal in-situ technologies and current projects. Potential of new technologies are assessed and compared to various existing in-situ thermal processes. Critical issues affecting production performance are discussed.
Prediction of Hydrogen Sulfide and Carbon Dioxide in HPHT Wells
Authors: Grimes William D. , McNeil Robert I. 
Published: December 2007

Abstract
It is can be readily demonstrated that hydrogen sulfide (H2S) and carbon dioxide (CO2) partial pressure can be estimated based upon formation temperature for hot (&gt;275ºF), high pressure, high temperature (HPHT) clastic reservoirs. This knowledge is extremely useful in the practice of sour service materials selection and materials qualification.
In fact for H2S, for early, untested wells in a field development program, it is recommended that these geochemical projections be used even if downhole sample analysis results are less than the projection. Even minor errors in H2S parts per million (ppm) due to filtrate, sample process, or analytical scavenging may lead to significant errors in equipment materials selection. The sensitivity to these H2S sampling errors is especially critical in the temperature range of 300-380ºF.
Likewise, CO2 can also be estimated, and the results of these two correlations can be used for pH prediction of downhole conditions. The resultant projected gas acidity and pH is then useful in ISO 15156/NACE MR01751 materials qualification work and corrosion control planning
Wireline Evaluation Technology in HPHT Wells
Authors: Sarian Serko , Gibson Arthur 
Published: December 2007

Abstract
Traditionally Wireline logging tools are rated for continuous operation to 350°F and 20,000 psi downhole conditions. With many reservoirs exceeding these limits, the need for specialized, High-Pressure and/or High-Temperature Wireline tools has been an issue for some time. Sensors were accordingly developed to ratings of 500°F and 25,000 psi. Recently, Ultra-Deep drilling has pushed the boundary to above 25,000 psi, resulting in the development of 30,000 psi and 500°F rated wireline tools. Currently, basic Petrophysical evaluation Quad-combo strings are available and wells in excess of 480°F, 26,000 psi have been successfully evaluated. Significant work is underway to upgrade specialized wireline services such as pressure testing, fluid sampling, dipmeter imaging, sidewall coring, Dipole Sonic, Magnetic resonance, natural and spectral Gamma ray measurements.
Like most other oilfield services, Wireline HPHT technology development pauses serious challenges. When the extreme is temperature or pressure only, the solution is relatively simple. Significant complications arise when both extreme conditions occur simultaneously, requiring at times timely and costly redesign of sensors and related electronics. The paper follows Wireline HPHT evaluation development to date, outlines technological challenges and barriers to continuously expand current tool rating limits while increasing the range of services. Recent case histories from North America are presented. Finally future development and well evaluation technology trends are discussed.
The Role of Idealization Uncertainty in Understanding Design Margins
Authors: Klever Frans J. , Tallin Andrew G. 
Published: December 2007

Abstract
Limit states design is based on explicitly modeling the likely failure modes. Design margins ensure safety and durability by accounting for uncertainties in loads, strength, environmental exposure and idealization. This paper examines the idealization or model uncertainties. These uncertainties are particularly important when extending the limits of conventional design, such as HPHT well design.
The purpose of the paper is to discuss how such uncertainties could be handled for fracture mechanics based limit states. The paper provides a basic overview of commonly used FAD methods and some of its limitations. A survey of published verification tests was made to see whether this data could be used to estimate FAD idealization uncertainty.
The authors conclude that available data is not directly applicable to well design. A testing program is recommended to establish the model uncertainty for sour fracture of casing.
A Case History of Sustainable Annulus Pressure in Sour Wells – Prevention, Evaluation and Remediation
Authors: Milanovic D. , Smith L. 
Published: December 2007

Summary
This paper describes evaluation of the possible causes of Sustainable Annular Pressure (SAP) in a sour gas field in the Middle East. It explains the diagnostic testing undertaken and describes how evidence was used to identify the cause of the SAP. The steps taken to prevent the occurrence of SAP in new wells and to remedy the problem in existing wells are described.
This practical approach, based on critical assessment of many aspects of the whole well condition put the SAP problem under total control, covering the process from well design through the lifecycle of the well. This all-encompassing approach is regarded to be essential for all sour gas wells, but especially for HPHT designs.
The Submersible Pump: It Can Be Compatible with Surface Equipment
Authors: Durham Marcus O. , Boyer Lynn 
Published: December 2007

ABSTRACT
A method of selecting submersible pump equipment is outlined which emphasizes economics, conservation, and compatibility. Reduction of inventory expense is demonstrated by elimination of specialized components. The system is designed to minimize waste energy due to power drop in submersible cable. Interchangeability between submersible and surface installations is obtained by prudent selection of transformers and controllers. An installation containing 40 submersible pumps is used for evaluation of past practices and our systems approach. An economic comparison is made with this data.
Numerical Studies of Oil Production from Initially Oil-Wet Fracture Blocks by Surfactant Brine Imbibition
Authors: Adibhatla B. , Sun X. , Mohanty K. K. 
Published: December 2007

Abstract
Little oil can be produced from fractured oil-wet reservoirs by water flooding. Introduction of surfactant into the brine phase can improve the oil production by lowering the oil-water interfacial tension (IFT) and by altering the wettability of the matrix block to water-wet. A 3-D numerical simulator is developed to model this process. The capillary pressure, relative permeability and residual saturations of both phases are considered as functions of IFT and wettability, which are correlated to the surfactant and salt concentrations based on the data obtained from laboratory experiments. The mass balance equations are solved with a fully implicit scheme. Numerical simulation matches the experimental data obtained for alkaline surfactant imbibition. Simulation results indicate that both capillarity and gravity help to improve oil production: in the early stage of the production, capillarity is found to be the major driving force, and in the later stage, gravity dominates the production. Surfactant diffusion into the matrix block leads to IFT and wettability alterations which in turn lead to oil mobilization. Oil recovery by the time surfactant completely diffuses into the matrix block is found to be about 30% of the total recovery. As matrix block height increases, or surfactant alters wettability to a lesser degree, or permeability decreases, oil production rate decreases.
Three-Dimensional, Randomized, Network Model For Two-Phase Flow Through Porous Media
Authors: Lin Cheng-Yuan , Slattery John C. 
Published: December 2007

ABSTRACT
A structural model for a porous medium in the form of a randomized, three-dimensional network is developed that can be used to calculate permeability, capillary pressure as measured under static conditions and during steady-state flows, and relative permeabilities as measured during steady-state flows.
This randomized network model, expressed in terms of seven free parameters, can be employed to correlate for a given system the single-phase permeability, the drainage and imbibition capillary pressure curves, and the two drainage relative permeability curves. The subsequent portions of the hysteresis loops for capillary pressure and for the relative permeabilities then can be predicted.
The limited data available from the literature for unconsolidated packed beds have been successfully correlated: 100 to 200 mesh sand and uniform 181 μm glass spheres. Data for a bed of sintered 200 μm glass beads also has been successfully described.
The Next Step: Personal Responsibility for Safety
Authors: Bowyer M. , Sawaryn S. J. , Smith N. 
Published: December 2007

Abstract
Improvements in technology and systems have greatly reduced injury rates in the oil and gas industry. To seek further reduction, in the mid 90's, focus shifted to behaviors and culture. In the UK continental shelf, the Step Change in Safety (SCIS) initiative has played a major role in improving safety since its formation in 1997. Improvements have been achieved by fostering collaboration between its 128 members, including employees, service companies, operators, trade unions, regulators and representative bodies. It is recognised that good practice can be found in most aspects of safety in this large and diverse membership. The challenge is to bring these together in a harmonised approach.
In 2003, SCIS launched a "Personal Responsibility for Safety" (PRfS) programme to prepare and deliver common guidance to assist the acceptance of Personal Responsibility for Safety. This guidance highlights good practice that will assist in driving further improvements in safety performance. A workgroup categorised safety behaviors in 9 elements. A simple questionnaire was then used to target more detailed interviews and acquire source material from more than 30 companies. The material covers: setting expectations, communication, leadership, risk awareness, planning, intervention, accountability, self evaluation and sustaining safe behaviors. The PRfS guidance document has been published, the next step towards the goal of making the UK the safest place to work in the world-wide oil and gas industry.
This paper contains a detailed discussion of the development of PRfS in the UKCS, and the later rollout and response. Brief details of the project's organisation and execution have been included for those interested in organising a collaborative effort on this scale. The paper will be of interest to individuals, supervisors and managers wishing to understand, establish, or improve a culture of personal safety in their organisation.
Phase Behavior Effects on the Oil Displacement Mechanisms of Broad Equivalent Weight Surfactant Systems
Authors: Gash Bruce W. , Griffith David T. , Chan Albert F. 
Published: December 2007

ABSTRACT
Multi-component micellar fluids containing broad equivalent weight surfactants, such as vacuum gas oil (VGO) and polybutene sulfonates, are being considered for commercial applications of micellar flooding. These surfactants are attractive for such applications because they are considerably less expensive than the more pure sulfonates.
A phase behavior study of micellar fluids containing VGO sulfonate as a function of salinity, hardness, brine dilution, temperature, cosurfactant type, and surfactant-cosurfactant ratio was used to define the region within which stable micellar fluids can be formulated. The phase behavior study demonstrates that for micellar formulations within the stable region that contain 10 wt. % surfactant, the addition of an equal volume of oil (decane) normally produces Type I microemulsions (Winsor's notation). More dilute micellar fluids (1 wt. % surfactant) show Type III behavior. Effluent analyses from corefloods show that VGO sulfonate remains almost exclusively in the water phase (although a small amount of Type III microemulsion was observed in some of the effluent). This suggests that the recovery mechanism for the VGO sulfonates is dominated by the Type I lobe of a Type III phase environment.
Phase behavior tests of polybutene sulfonates show that in the presence of calcium the sulfonate partitions into the oil phase forming microemulsions in a Type II lobe of a Type III phase environment. During displacement tests in the presence of calcium, polybutene sulfonates partition into the oil phase generating such microemulsions in situ.
The use of a Type II to Type I phase transition in moving partitioned sulfonates was investigated. Type II microemulsions generated external to the core were injected to displace the in-place oil. These were followed by a fluid designed to produce a phase transition from Type II to Type I. The Type II microemulsion miscibly displaced the inplace oil. The phase transition microemulsion flood displaced oil more efficiently at higher salinity and hardness levels than has been obtained using conventional micellar fluid formulations of VGO and polybutene sulfonates.
SDLA: Fighting Skin Damage in Colombian Fields—A War Story
Authors: Franco C. A. , Restrepo A. , Acosta L. G. , Junca E. 
Published: December 2007

AbstractThe well damage history in the fields operated by BP Colombia has showed an interesting performance in all producer and injector wells. The abnormal productivity decline detected since the start-up in 1991 was a clear evidence of the skin damage magnitude, in fact, the fields have not plateau history. The initial high oil and gas rates production added to strong geological structures in which a variety of fluids have been producing (critical volatile and gas condensate) have contributed to the development of a very complex damage scenario; main damage factors identified at early stage of production were fines migration and mineral scales (calcite, siderite, barite, celestite and iron compounds). Research regarding acid stimulation and mineral scale inhibition was the first step trying to mitigate the high oil rate decline. New damage mechanisms were detected as long as the fields were in production, water and condensate blockage, organic scales (wax and asphaltenes), iron sulfide scales, and wettablity changes were the main damage mechanisms detected. Engineering work, laboratory and geological studies, backflow analysis, third parties investigation and an extensive field trial program have been developed to determine the best stimulation program that should be applied in each one of producer/injector wells. Although high success removing formation damage has been obtained, it has been necessary to focus additional effort to find and test new technology addressed to increase both IIOR and stimulation lifetime.
Appraising Feasibility of Tertiary Recovery with Carbon Dioxide
Authors: Kelm C. H. 
Published: December 2007

Abstract
Amoco Production Company has been and is continuing to investigate the potential for recovering tertiary oil by CO2 flooding. Tonight I will discuss a method for appraising the feasibility of tertiary recovery with carbon dioxide.
This method was applied initially to the evaluation of eleven Amoco operated properties in seven fields in the Permian Basin. These projects, which are currently being waterflooded, encompass 2300 producers and 1600 injectors. In addition, several other properties are currently being evaluated using this same approach.
In the evaluation of a plan of depletion, the basic components necessary for determining economics are estimated costs and predicted performance. Accurate estimates of these two parameters are especially critical in appraising tertiary recovery with CO2 because of high initial costs, extremely high operating costs, and the long lead times required for flood implementation. Compounding the risk associated with it being a high cost project, CO2 tertiary flooding is a complex process. For example, waterflooding was a "forgiving" process. If water breakthrough occurred prematurely, we handled it fairly simply. But with CO2 it may be a different story and to top it off, CO2 tertiary flooding a waterflood project may prove detrimental to waterflood performance should the tertiary flood be unsuccessful.
The Impact of Measurement Error on Deliverability Projections for Tight Gas Wells
Authors: Hale Brent W. , Mahmood Alice M. 
Published: December 2007

ABSTRACT
Many papers have been written attempting to describe the basic parameters of a tight gas reservoir. Normally, a reservoir is described using a combination of geological and transient pressure data. This paper does not propose specific methods for measuring or for interpreting the required data. It relates parameters measured by initial well tests to long term deliverability projections.
Partly because data is subject to error, various interpretations can result. This paper discusses the impact of measurement error on deliverability projections for tight gas wells. It relates measurement error to long term interpretation error so that long term interpretation error can be minimized.
Uinta Basin Lenticular Sandstone Reservoir Characteristics
Authors: Boardman Charles R. , Knutson Carroll F. 
Published: December 2007

ABSTRACT
Previous analysis of production curves, from tight gas sand wells in the Uinta Basin of Utah, identified three types of performance - linear, intermediate and near radial. Six wells were selected, covering this distribution, and an attempt was made to determine dynamic reservoir gas volumes, and to compare these "production" volumes with volumes calculated from several different lenticular sand models.
Volumes of the 29 tight gas sandstones present in these six wells were approximated by using long term pressure buildups to calculate present pressures (and permeabilities). Then reservoir volumes were calculated using p/z vs cumulative production plots extrapolated to zero pressure. The average reservoir volume is interpreted to be about 240,000 cubic feet per foot of net pay.
The "production" volumes are compared with the equivalent calculated volumes using four different modeling techniques.
Reservoir Volume, 106 cu ft. Sum of All Wells Well C Production Volume 75.3 10.8 Knutson Model Volume 60.7 – Knutson/Ward Model Volume 86.0 – Baker Model Volume 10.6 Gidley et al Model Volume 136.1 –
The Knutson/Ward and Baker models seem to provide the best approximation of the "production" data. This approximation may have been better if a more sophisticated pressure buildup analysis had been used.
Apparent reservoir permeabilities, assuming radial flow, range from .009 to .052 millidarcies and actual sandstone matrix permeabilities are interpreted to range from .06 to .21 millidarcies.
The Operational Excellence Roadmap: A Tool for Implementing Operational Excellence in Major Capital Projects
Authors: Dehmer S. 
Published: December 2007

Abstract
To achieve world-class performance, major capital projects must successfully implement Operational Excellence (OE): the systematic management of safety, health, environment, reliability, and efficiency. When compared to operations, implementation of OE in capital projects provides unique challenges because it will vary depending upon the project phase (e.g., design, construction, etc.). A special tool, the OE Roadmap, was developed to assist projects in addressing these implementation challenges.
Determination of Fluid Corrected Porosity in Tight Gas Sands and in Formations Exhibiting Shallow Invasion Profiles
Authors: Kukal Gerald C. 
Published: December 2007

ABSTRACT
Log-core correlations from four Upper Cretaceous wells in Rocky Mountain basins demonstrate that the axiom "high porosity - shallow invasion, low porosity - deep invasion" is not valid in tight gas sands. The data suggests that the zone of flushing is typically much shallower than the density tool depth of investigation. This results in too high density interpreted porosity in low permeability gas sands. The discrepancy is generally 3-4% porosity in gas sands having 8-12% porosity as determined from core analysis.
Rigorous log quality control was maintained in the field. This included monitoring of the before and after density calibration record, multiple repeat runs over the cored intervals, slow logging speed, monitoring of tool stability, and digital logging. Whole core Boyle's Law helium porosity and grain density measurements were made on every foot of potential reservoir sand. Core measurements are depth shifted to log data using a combination of core gamma, lithologic description, and a plotted core data overlay. A crossplot of core porosity versus density log calculated porosity is presented for each well. Log calculated porosities are based upon bulk density, the grain density value of each correlated core measurement, and the customary assumed fluid density of 1.00 g/cc.
By combining plots of all four wells, a non-linear trend is established for conversion of apparent density porosity to true porosity. The trend has the characteristic of closure to unity for the higher and very low porosity values, with greatest divergence from unity in the middle porosity range. Formations having higher water saturations show less divergence in the middle porosity range.
An iterative mathematical model is developed for calculation of "Sxo" and effective porosity. The "Sxo" is actually the average water saturation of the zone investigated by the PGTK density tool and the CNTA thermal neutron tool. This system provides more reliable porosities and may have application as an indicator of potential formation producibility. The technique also has application in other shallow-invasion type borehole environments, e.g., air-gas drilled holes, oil base systems, and underbalanced drilling systems.