bluuebunny/crossref_metadata_2025_split huggingface dataset:
Importance of Completion Design Considerations for Complex, Hostile, and HPHT Wells in Frontier Areas
Authors: Hahn D. E. , Pearson R. M. , Hancock S. H. 
Published: December 2007

Abstract
As upstream oil and gas exploration and production companies search for new opportunities, much deeper wells are being drilled and completed. In addition to greater depths, an increasing number of wells are being drilled and completed in much more hostile downhole environments. These very complex wells are frequently drilled in frontier areas around the world, including the Western and Northern Canadian foothills and coastal areas. Where pressures exceed 10,000 psi (69 MPa) and temperatures surpass 300°F (149°C), wells are generally termed High-Pressure/High-Temperature (HPHT) completions.
The stresses resulting from the combination of high axial loads and pressure differentials begin encroaching on materials limitations of standard subsurface equipment. This paper provides an overview of an engineering design methodology that can be used during the planning of deep, difficult, or complex wells. The importance of numerous design considerations and realistic, clearly defined load cases will be emphasized.
High temperatures cause the well to operate with either significant pipe movement, or high compressional loads at the packer, particularly when these high temperatures are combined with higher operating pressures. The increased well depths, usually with accompanying deviations from vertical, also increase mechanical and fluid friction. These situations require a rigorous engineering analysis with the aid of modern thermal and stress analysis software.
Traditional uniaxial and biaxial working stress designs are convenient and usually adequate for shallower, lower temperature/pressure wells. However, the severe conditions considered within this paper require state-of-the-art triaxial design software. Examples within the paper will demonstrate how the results of these simulations can be used for hostile environment tubular selection, including discussion of the importance to properly select and test the tubular connections.
Many failures have resulted from brittle fracture or fatigue rather than yield, because the tendency for the designer is to choose higher yield strength materials that are inherently less ductile and more prone to hydrogen embrittlement. To avoid this, it is better to push the limits of lower strength, ductile materials, which in turn challenges the typical design safety factors. This challenge has lead some major oil companies to develop and use risk based tubular design processes.
Gas Production from Low Permeability Carbonates Enhanced through Usage of New Acid Polymer System
Authors: Metcalf Steve , Lopez Henry , Hoff Charlie , Woo George 
Published: December 2007

Abstract
Gas production from the Strawn Limestone formation in Crockett County, Texas is generally only commercial after stimulation. Historically, the most successful stimulation treatments typically consist of large acid fracturing treatments. Several techniques have been used, including gelled acid, gelled water pads and gelled acid pumped in alternating stages and crosslinked acid systems.
Gelling of acids has been accomplished for years using emulsions to facilitate the addition of polymer to acid to achieve good hydration. Recently, a new emulsion system and polymer were introduced into this area which significantly improved efficiency both in developing fluid properties and operations on location. The micelles of this new polymer emulsion are approximately 1/15th the size of those previously applied. The polymer emulsion uses a highly specific external activator to initiate and promote hydration, dramatically reducing the formation of "fisheyes". In addition, it allows for continuous mix operations on location.
Production results are presented from three wells, showing a 34% improvement in production in which the new polymer system has been used. In addition, production responses to several different treatments are compared, which show crosslinked acid fracture treatments to be the most successful. Treatment details along with a description of the new emulsion chemistry and operational advantages are presented.
Determining Liquid Carry Over in Gas Condensate Production Facilities and Assessing the Flow Regime in the Gas Sweetening Carbon Dioxide Amine Units Offshore on the Sleipner Platform in the North Sea
Authors: Georgie Waleed J. , Nilsen Jan I. , Håland Trygve , Solheim Erik , Lyth Chris J. 
Published: December 2007

Abstract
The produced gas from Sleipner West field area contains up to 9.5 % carbon dioxide 1, 2 and is almost free of hydrogen sulfide. Gas handling facilities on the platform were designed to reduce the level of CO2 to the export criteria of 2.5%. During the start up phase of production and the three years of operation period that followed, the required level of carbon dioxide removal of 2.5% was not achieved, and in most cases the CO2 level in the gas export was averaging 3.5% or higher. Although the slightly higher level of CO2 in the gas export did not cause any major problem, since the export stream from Sleipner West production is mixed up with relatively carbon dioxide free gas (less than 1.0%) from the main Sleipner East production area, it was important to provide complete flexibility in the Sleipner West gas treatment facilities to meet the export criteria of 2.5% CO2.
Poor performance of the amine absorbers in removing the CO2 in the gas phase was thought to be related to the condensate build up in the amine solution. Significant foam build up in the amine absorbers was a good indication of condensate build up caused by carry over and / or condensate retrograded in the pipe work between the different vessels.
Organic, aqueous and gas based radioactive tracers were used extensively in the gas processing facilities and the carbon dioxide removal gas sweetening plant on Sleipner West treatment production platform (SLT) in the North Sea. The use of radioactive tracer techniques within the platform facilities provided semi quantitative data on the level of the liquid carry over from the condensate stabilization process train to the gas plant over a period of three years. In addition, by utilizing the technique in the amine absorbers within the carbon dioxide removal plant, a clearer picture of the flow regime within the tower emerged and was developed. Using the data generated from these studies, as well as plant and system performance data, a full assessment of the poor CO2 removal efficiency was carried out in order to identify the potential problem and determine the required and necessary modifications to the treatment facilities on SLT.
A combination of plant offshore studies, process simulation, laboratory analysis and radioactive tracer studies were utilized to identify and rectify the problem. The data generated from the latter studies were considered an important part in developing an understanding of the problem in the process system on Sleipner West treatment plant. This paper addresses the approach used in utilizing the radioactive tracer techniques in providing a tool for determining carry over and flow regime within the process vessels.
Development of an Intelligent Systems Approach for Restimulation Candidate Selection
Authors: Mohaghegh Shahab , Reeves Scott , Hill David 
Published: December 2007

Abstract
This paper summarizes the development of a methodology for the restimulation candidate selection in tight gas sands. The methodology incorporates virtual intelligence techniques (artificial neural networks, genetic algorithms and fuzzy logic) to achieve this objective. Artificial neural networks are used to develop a representative model of the completion and hydraulic fracturing process in a specific field. Genetic algorithms are used as a search and optimization tool to identify the missed incremental production based on the neural network model. Finally fuzzy logic is used to capture the unique field experiences of the engineers as well as detrimental parameters (if such parameters are indeed present) and incorporate them in the decision making process. Approximate reasoning approach is used at the decision making level to identify the restimulation candidates. Once the methodology is introduced, it is applied to an actual tight sand field in the Rocky Mountain region and the results are presented.
Practical Technique to Identify Infill Potential in Low-Permeability Gas Reservoirs Applied to the Milk River Formation in Canada
Authors: Hudson J. W. , Jochen J. E. , Jochen V. A. 
Published: December 2007

Abstract
This paper describes the application of a practical technique to determine infill potential when faced with little time, large data sets, and complex geology. Using this technique, we determined where newer wells are encountering potentially depleted reservoir and the infill potential for the Milk River formation within a 900-well, 200,000-acre area in the Western Canada Sedimentary Basin. We obtained these results in a minimal amount of time and used only monthly production and wellbore location data. We validated our technique by "history matching" the production performance of recently drilled wells. We correlated well quality with historical well densities in order to predict the infill well potential from 160-acre spacing to an 80-acre well spacing. We estimated ultimate recoveries for all existing wells and infill candidates and show their reserve distributions. We identified 896 infill candidates with 8.9 × 109 m3 of gas reserves. The results of this study are presented in this paper using tables, graphs, and maps.
The results of a study applying this analysis technique can be used when budgeting and planning near-and long-term drilling programs. The analysis techniques described in this paper could be applied by operators in other areas and reservoirs to evaluate their own acreage position or infill drilling potential.
New Approach for Simultaneous Determination of the OGIP and Aquifer Performance with No Prior Knowledge of Aquifer Properties and Geometry
Authors: Vega L. , Wattenbarger R. A. 
Published: December 2007

Abstract
Traditionally, the p/z plot has been used to describe the behavior of volumetric depletion gas reservoirs. Several authors1,2,3, 4 have pointed out, though, that this technique can lead to serious misinterpretations of the drive mechanism and overestimation of the original gas in place (OGIP) if the reservoir produces under the influence of an encroaching aquifer.
Although regression analyses have been presented5,6 to obtain a more accurate aquifer description, a solution to the non-uniqueness problem still relies on a prior knowledge of the aquifer properties and geometry.
The approach proposed here makes use of aquifer influence functions. A general pattern of the normalized absolute error function allows the simultaneous determination of the OGIP of a reservoir and a description of the aquifer performance. No assumptions regarding aquifer properties or geometry need to be made.
Reserves to Production Ratios and Present Value Relationships
Authors: Hayhow I. G. , Lemee J. A. 
Published: December 2007

Abstract
Reserves to production ratio (R/P) is equivalent to the inverse of an exponential decline rate which is commonly used to forecast production rates. For a tank type gas reservoir, adding wells will increase the pool's producing rate and reduce the reserves life and R/P. Therefore, R/P indirectly represents the amount of development. For this analysis the optimum R/P is the value which results in the highest present value.
An approximation of present value for a single pool is represented by a single equation which takes into account the number of wells in the pool, initial productivity, capital cost per well, decline rates, discount factors and the netback received. A second equation has been derived to calculate the optimum R/P or the amount of development, which will yield the maximum present value. The results from these equations are not precisely the same as those determined by the cash flow model, but they are useful for checking sensitivities to various input parameters. The equations show that every pool has a unique maximum present value which is dependant on pool size, productivity, capital cost, number of wells, etc. However, the R/P at which the maximum present value occurs is only dependant on the ratio of individual well productivity to its capital cost (q/c). The equations also show that the optimum R/P decreases for pools with higher q/c ratios. This dependency to q/c ratios suggests that the optimum R/P for recently discovered pools will likely be lower than for older pools of equivalent reservoir quality because of improvements to the q/c ratio. New producing techniques such as horizontal wells and the utilization of an established infrastructure have increased productivity relative to the capital invested.
The optimum R/P's have been determined for a number of pools using the equations and these results have been compared to values derived from a cash flow model.
Evaluation of Fluid pH Effects on Low Permeability Sandstones
Authors: Simon D.E. , McDaniel B.W. , Coon R.M. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
The continued success of completing commercially producing wells in formations with permeabilities in the 0.5 to 0.01 millidarcy range has resulted in the need for laboratory techniques in evaluating the effects of water base stimulation fluids on the formation matrix. Use of fluid flow tests becomes nearly impossible and results are generally inconclusive when the air permeability is less than 0.5 md. Still, the permeability is less than 0.5 md. Still, the need exists for evaluating the compatibility of potential aqueous stimulation fluids with formation minerals.
The purpose of this paper is to report on the use of the Scanning Electron Microscope (SEM) to evaluate the effect of pH of aqueous base fluids on clay minerals associated with the pore space. Included are SEM photomicrographs showing sample areas before and after exposure to aqueous fluids with emphasis being placed at the pore openings. All work is directed toward low permeability sandstone formations.
This study is concerned with the effect of pH on the relatively nonswelling clay minerals, kaolinite, chlorite, and illite, as well as the more highly water swellable clays, mixed layer and montmorillonite. By examining SEM micrographs of a small area of the core before and after exposure to fluids with different pH values, it can be seen that the formation rock samples tested are in general, more compatible with low pH fluids than with high pH fluids.

Introduction
In the past few years, the energy crisis has caused the price of natural gas to increase at an unprecedented rate. Higher prices now being paid for natural gas have greatly increased the importance of low permeability reservoirs, many of which are sandstone formations containing significant quantities of clay minerals. Presence of clays causes concern when use of a water base fluid is contemplated. Prior to this time, the only reliable testing procedure for evaluation of fluid procedure for evaluation of fluid compatibility in low permeability sandstones was the use of time consuming "Regained Gas Permeability Tests". This required specialized equipment with costly mass flow meters to accurately measure the very low gas flow rates.
This paper presents a new procedure utilizing the Scanning Electron procedure utilizing the Scanning Electron Microscope (SEM) to evaluate formation compatibility with aqueous base fluids.
Hydrodynamic Investigation of Gas-Condensate Wells Based on Hysteresis Phenomena
Authors: Panfilov M. , Kabanov N. 
Published: December 2007

Abstract
The theory of in-situ experiments destined to obtain the information about the relative permeability for gas-condensate mixtures is elaborated. Theoretical basis is the analytical solution of the nonlinear problem of flow towards a well obtained by the asymptotic methods of singular perturbation theory. Analysis of the solution has shown the saturation field to be sensible to some particular modes of flow rates variation in time, which comprises as increasing, as decreasing of the flow rate. Analyzing the hysteresis loop of the wellbore saturation as the function of flow rate, we define the relative permeability for liquid. The relative permeability for gas results from the measurement of the borehole pressure.
Use of the Natural Gas of Camisea Peru for Electric and Gas Systems in the North of Brazil
Authors: Carrera Guido Z. , dos Santos Edmilson M. 
Published: December 2007

Abstract
The Amazon region has been demonstrating a great oil and gas potential in Brazil and in the neighboring countries, specially the field of Camisea in Peru. However, the development of feasible and economically justifiable transport systems, that can allow the flow of those resources to their potential markets, continues to be the great challenge. In this work, we present one option that can be transformed into competitive and commercial project. We describe a gas pipeline option, discussing about their technical, economic and commercial aspects. We suggest that the fields already discovered in the area should be treated in an integrated way, achieving larger economies of scale in more ambitious initiatives aiming at exports.
The Development and Application of an Accurate Assay Technique for Sulphonated Polyacrylate Co-polymer Oilfield Scale Inhibitors
Authors: Chilcott N. P. , Phillips D. A. , Sanders M. G. , Collins I. R. , Gyani A. 
Published: December 2007

Abstract
Chemical inhibitors that prevent the formation of sulphate and carbonate mineral scale formation are used in field squeeze treatments. The demand for competent evaluation of all issues associated with mineral scaling in wells and pipelines is continuous throughout the lifetime of any producing asset and the cost implications are very large. It is therefore important that the chemical inhibitor species can be accurately assayed so that the end of the squeeze lifetime can be determined.
Previous work by others has reported the development of accurate detection and assay techniques for oilfield scale inhibitors1,2. For PVS and VS-Co type inhibitors, these methods involve pre-treatment/purification stages that allow the application of standard wet chemical techniques, in particular the separation of the inhibitor chemical from interfering brine salts. However the typical size of samples from experimental core floods are so small that they render these methods impractical.
In this paper we detail the development of a turbidimetric method without the need for pre-treatment/purification stages for the determination of a sulphonated-polyacrylate co-polymer using Hyamine 1622. The applicability of this technique is illustrated with coreflood samples having small volume size and with real field post-scale inhibitor squeeze produced water samples. It is also shown that the method developed allows the determination of scale inhibitors in produced waters with up to 55,000ppm total chloride concentration and 100ppm crude oil in water.
Finally we report the potential interferences caused by the inhibitor carrier, crude oil and displacement fluid which may arise as a result of both typical and atypical squeeze treatments.
Increasing Squeeze Life on Miller with New Inhibitor Chemistry
Authors: Bourne H M , Williams G , Hughes C T 
Published: December 2007

Abstract
The water chemistry prevailing in the BP Amoco operated Miller field presents one of the harshest scaling environments in the North Sea. The high barium, moderate salinity brine, coupled to a relatively high bottom hole temperature produces a scaling environment that dictates the need for high concentrations of exotic scale inhibitor chemistry for downhole scale control. These high levels of inhibitor, typically 10-200 ppm, are particularly difficult to sustain over long production periods. This leads to a relatively short squeeze life and thus high well intervention frequency and deferred oil costs.
Vinyl sulphonate chemistry has been shown to be particularly effective at controlling scale deposition under Miller conditions. However, its retention characteristics are less than ideal, leading to short treatment life. A new chemistry has now been developed which realises the benefits of the vinyl sulphonate functionality whilst achieving significantly higher retention and thus the potential for longer treatment life. This has been achieved by incorporating a novel phosphorus containing species into the polymer matrix.
Laboratory studies suggest that the new inhibitor combines significantly improved performance with superior environmental properties. One field trial has already been completed and another is currently ongoing. The trials have already achieved a significant increase in squeeze life.
Results to-date indicate that operating costs can be significantly reduced through development of a novel chemistry designed to meet the specific needs of a particularly harsh scaling environment.
Interpretation of Bottom-Hole Pressure Build-up Tests on Fractured Oil Reservoirs
Authors: El-Hadidi Samir M. , Ritter A.E. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
This paper is designed to develop a procedure to analyze pressure buildup curves procedure to analyze pressure buildup curves where radial flow theory does not apply.
In a vertically fractured system, which is present in most West Texas carbonate reservoirs, present in most West Texas carbonate reservoirs, flow in the region nearest the fracture is essentially linear, whereas, further out in the formation, radial flow normally prevails. Historically, interwell flow capacity, fracture length, wellbore damage and static pressure have been determined using the late time slope from pressure log time curves. This solution is pressure log time curves. This solution is based on a radial flow model and, as a result, most of the computed reservoir parameters are in error.
A set of guidelines are established to allow uniform interpretation of pressure buildup curves and to determine the best workover candidates for fractured oil reservoirs. Field examples representing four basic cases are also presented. presented

Introduction
The presence of natural or induced fractures will influence the flow behavior in oil reservoirs. In a fractured system, flow in the region nearest the fracture is practically linear, whereas farther away from the fracture, essentially radial flow prevails. Thus, transient pressure analyses based on radial flow theory are incorrect when applied to reservoirs where linear flow predominates.
In the past few years, the slope and position of the straight-line portion from position of the straight-line portion from transient pressure vs the logarithm of shut-in time plot has been used exclusively to determine the flow capacity, condition ratio and static pressure for oil wells with natural or induced pressure for oil wells with natural or induced fractures. In most cases, the straight lines used have not been the proper ones. A stable pressure gradient was never reached in these pressure gradient was never reached in these cases; however, equations based on conventional radial flow theory were used. This resulted in the improper calculation of a condition ratio greater than one, of higher than actual interwell flow capacity, and of an improved wellbore condition where, in actuality, wellbore damage might exist.
The calculation procedure presented in this paper enables the user to detect the conditions paper enables the user to detect the conditions around the wellbore and aids in determining whether the well is a good candidate for workover.