bluuebunny/crossref_metadata_2025_split huggingface dataset:
Economic Model for Gas-to-Power Project Capitalization in Developing Economy
Authors: Osaghae Ephraim Osagie 
Published: December 2007

ABSTRACT
Gas-to-power electricity generation is an effective means by which oil and gas companies can move natural gas from both onshore and offshore reserves to the market. But due to the peculiar risks in developing regions like Nigeria, very little progress has been made in project capitalization in this energy sector.
In this paper, an integrated economic model, made up of the basic cash flow, scenario, and risk simulation analyses has been developed. Authors of similar works stopped at this level. But here, based on projects’ risk profile, companies equipped with their risk aversion levels (1/investment capital initially) can obtain their risk-discounted profits and hence able to decide whether to invest or not. Decisions on best shares for capitalization can also be obtained in real time. A gas-to-power System of 5 MMscfd gas supply generating 14.4MW electricity was used as the test project. A 20-year project life was assumed.
The results show that the natural gas supply aspect of the project is more profitable, earning US$1.84 per US$1.00 investment as against US$1.29 for the power generation. Profits of gas-to-power projects are mostly affected by changes in gas and electricity prices and supply reliabilities. For capitalization, investor A, an independent oil company with US$10 million investment capital can capitalize this project all alone (100% best share) obtaining a risk-discounted profit of US$4.34million. But investors B and C with US$2million and US$1.33million capital would have to share in 60%:40% project participation ratio earning US$1.55million and US$1.03million respectively to profitably capitalize the project.
With this model, gas-to-power risks are proactively identified, evaluated and communicated for effective decision-making. Best shares for profitable project capitalization even in a developing economy like Nigeria are easily determined.
Gas Exploration and Development Strategies in the Western Canada Sedimentary Basin
Authors: Flint D. W. , Dixon R. K. 
Published: December 2007

Abstract
The Western Canadian Sedimentary Basin (WCSB) is a major source of natural gas supply for the North American market, with Y2000 basin productivity at more than 16 Bcf/d. Significant natural decline requires that in excess of 3 Bcf/d of new supply must be added each year simply to maintain constant basin deliverability. In addition, the average rate added per well continued to decrease while the initial decline rate increased. During the decade of the 1990s, over 25 Bcf/d of new western Canadian gas deliverability was added, from over 42,000 new producing well events.
Based on the year of pool discovery and the year that the area was first connected to the delivery system, there are four definable Exploration and Development strategies. Each of the four strategies (Exploration, Connection, Development and Renewal) contributed a significant amount of gas rate additions. What role will exploration and development strategies play in future gas supply?
This paper illustrates the trends in gas supply additions over the last decade, including a view of the geographic distribution, as well as other attributes. There is also a comparison of the portfolios of E&D strategies that operators employed. A brief synopsis of the methodology followed to determine a consistent measurement of gas rate-additions is also presented.
Careful analysis of the historical results has yielded useful insights for operators as they make their choices about their future activities.
Portfolio Management: What is the Contribution to Shareholder Value?
Authors: Schuyler John 
Published: December 2007

Abstract
Many companies devote considerable attention and effort to portfolio optimization. Yet most of the literature and experience tells us that shareholders will not pay a premium for diversification and that investors mostly prefer pure plays. Diversification, vertical integration and hedging help companies level earnings and cash flows through economic cycles. The improved stability assists with various stakeholder relationships and lowers debt, salary and transaction costs. However, risk mitigation comes at a price. Does it provide a positive net value to the shareholder?
Models of a large petroleum project, its parent company, and a typical investor household provide a way to estimate portfolio management's contribution to shareholder value. The core question in optimizing a company's asset and investment portfolios is: What should we be maximizing to best serve stockholder interests?
This paper describes the modeling approach and the results of simulating various portfolio characteristics. Three perspectives are examined: (1) owning related vs. independent business units, (2) owning a business whose performance is correlated to the stock market, and (3) hedging product prices. These strategies are valued from the stockholders' perspective. The simulation results provide support in designing corporate decision policy, including choice of the present value discount rate.
Downhole Measurement of pH in Oil & Gas Applications by Use of a Wireline Tool
Authors: Børeng Raymond , Schmidt Terje , Vikane Olav , Tau Liv A. , Dybdahl Bjørn , Dale Tor I. , Thowsen Oddfinn 
Published: December 2007

Abstract
The giant Statoil-operated North Sea oil field Statfjord is currently far down its production decline curve. During 23 years of production 60% of the STOOIP has been recovered, and the remaining reserves are characterized by complex distributions of oil, water and gas.
In order to obtain a cost-effective production of the remaining oil, an aggressive drilling and intervention programme is necessary. Future developments might also include a pressure blow down phase of the reservoir. Then large volumes of water will be produced to surface. So far the Statfjord Field has exhibited a fairly mild scale potential. Sulphate scale has been detected in several wells down hole, whereas carbonate scale when found is mainly above the down hole safety valve. Carbonate scale precipitation will be more severe in any future blow down phase with a lowering of the reservoir pressure. To improve carbonate scale prediction a "correct" down hole pH value is necessary. The prediction program will then be capable of performing a better tuning sequence and give more accurate predictions, refer references.
Petrotech has developed a pH sensor system for downhole use. In 2002 Statfjord performed a field test of this system by running it in a well with a "single phase" fluid sampling chamber. The water sample captured down hole was used to get a lab measurement of the pH in the formation water at reservoir temperature and pressure. This sample was then flashed to standard conditions and a full water and gas analysis was performed. The results were used in the MultiScale software program to calculate a pH value. The results indicated good correspondence between the pH values obtained from the down hole sensor, the water sample and the pH value calculated with the scale prediction program.
Organic Acids in Carbonate Acidizing
Authors: Buijse Marten , de Boer Peter , Breukel Bert , Klos Monique , Burgos Gerardo 
Published: December 2007

Abstract
This paper discusses the use of organic acid as a stimulation fluid in carbonate formations. Organic acids such as acetic or formic acid have been used for many years as alternatives to HCl, due to the retarded reaction rate, low corrosivity and reduced tendency to form acid-oil sludge in asphaltene rich crudes. In Venezuela, organic acids were pumped in acid fracturing treatments in deep hot limestone formations. Case histories are discussed in the paper. Although these treatments were very successful, optimization of the design was hampered by the fact that models for organic acid-carbonate spending did not exist.
In this paper a new model for acid spending is proposed that can be used for strong acids (HCl) and for weak (organic) acids and also for acid mixtures. Compared to existing (HCl) models the only new element is the acid dissociation constant, describing the differences between strong and weak acids. The model was verified by comparing simulated reaction rates with rates actually measured in the laboratory with the rotating disk. Results of acid fracture simulations, comparing etched length and width of organic acid with HCl acid are also discussed in this paper.
A Barium Sulphate Scaling Post Analysis on Dunbar
Authors: Mastin E. , Urbanczyk C. , Hurtevent C. , Falla M. , Caie D. , Maguérez M. 
Published: December 2007

Abstract
Due to the commingled production of reservoir and injected sea waters, the Dunbar Asset has had to face Barium sulphates scaling problems. In 2001, a post analysis was made over the entire past production history. This study was carried out by a team consisting of well productivity engineers, reservoir engineers and a production chemist from both Headquarters and the Affiliate.
The analysis was directed at two different objectives: Fulfil an operational need: A water based pre-emptive treatment applied in 1997 on well D02 caused a substantial reduction in well productivity. This adverse effect led to major uncertainty in the planning and design of new treatments. The Affiliate wanted a complete analysis of this problem in order to come up with new procedures.Learn from Dunbar experience for future developments: Would it be possible, through a production history analysis, to look in detail at the scaling phenomena in order to pinpoint facts or identify engineering tools that could be of use in new development projects? And, as a feedback for future similar projects, could we assess what advantages a nano-filtration plant might have offered?
Both the scaling process and the treatment impact were analysed. This was made easier by the fact we had available data from six production logging operations on a key well. In terms of modelling, Reveal model was used to assess physico-chemical related behaviours to be further exported into the Reservoir model. The results of this modelling were matched against actual production history
The paper will focus on the impact on well productivity of the scaling process as it was highlighted through the exercise. As a matter of fact, a relative manageable effect was observed after the first layer water breakthrough. The effect is much more severe after the second layer water breakthrough, which can create actual bridges into the tubing and consequently affect drastically the flow and can trap reserves from lowermost layers.
As this method allowed playing back the history, it opens tracks for planning and dealing with the perforation strategy. In other words, it places the scaling prevention concern right in the middle of the reservoir engineers' type of expertise.
Apart from technical consideration, the paper will also present quick economical issues. All scale related operating costs and production slowdowns have been compiled and weighted against the Capex and operating costs that would have represented a nano-filtration plant installed from the beginning. This consideration on economics is only meant as a reference point should we need to design developments in similar contexts, and still needs to be examined for any given project.
In-Depth Permeability Control by Adsorption of Soft Size-Controlled Microgels
Authors: Chauveteau Guy , Tabary René , Le Bon Christel , Renard Michel , Feng Yujun , Omari Aziz 
Published: December 2007

Abstract
Injecting stable, preformed microgels as relative permeability modifiers to reduce water production minimizes the risk of well plugging or the absence of efficiency inherent to a technology based on in-situ gelling. Recent investigations showed that microgels formed by crosslinking a polymer solution under shear are soft, size-controlled, quasi-insensitive to reservoir conditions, stable over long periods of time and can control in-depth permeability by adsorbing onto all types of rock surface. The new laboratory studies reported in this paper aimed at knowing how to control the kinetics of crosslink formation by ionic strength and at determining the role the interactions between microgels on their propagation in porous media. The reported experiments include: 1) gelling tests at different ionic strengths, 2) measurements of viscoelastic properties of solutions, 3) determination of both microgel density and microgel-microgel interaction parameter for different conditions of stabilization, 4) the relation between the interaction parameter and the mode of adsorption of microgels. Partly attractive microgels were found to adsorb by forming multilayers and thus to induce drastic permeability barriers. Fully repulsive microgels adsorb as a monolayer and propagate easily in porous media at long distances depending only on the quantity of microgel injected. Thus, by controlling both gelling and stabilization processes, microgels can be produced to be either diversion agents or disproportionate permeability reducers to control water permeability at long distances from the wells.
Calibrated Wireline Mechanical Rock Properties Model for Predicting and Preventing Wellbore Collapse and Sanding.
Authors: Ohen Henry A. 
Published: December 2007

Abstract
Compressive wellbore failure is a major contributor to sanding problems and casing collapse in many oil and gas fields. This type of failure occurs when the wellbore pressure exceeds the rock strength, typically in unconsolidated and weakly-cemented rocks or in consolidated rocks where stimulation programs may have removed or weakened the rock cement. The complex interrelationships between the physical factors that act on the wellbore to result in this type of failure makes the dynamic modeling of wellbore stability challenging. Most of the available models for predicting sanding and well collapse use openhole logs with very little success. The dynamic mechanical properties obtained from logs are typically too optimistic and hence require calibration to static measurements on selected core samples. It is, however, important to address issues relating to the representativeness and the relative volumes of investigation of the core data. The associated uncertainties of the core and wireline log measurement scales and conditions must be considered for an effective model.
This paper presents a systematic core-to-log integration technique that enables the static mechanical rock properties measured on rock samples to be used in the effective calibration of dynamic wireline data for mechanical log analysis. Relationships are developed between static and dynamic mechanical rock properties.
Three different field examples are presented that demonstrate that rock strength, optimum drawdown and compressive failure are related to reservoir rock quality and can be predicted by rock typing or flow units in sandstones. This work demonstrates that the flow units concept in combination with the mechanical logs may be used effectively as predictive tools for identifying weak zones that are prone to mechanical collapse and therefore should be avoided during completions. Some of the applications and benefits of the methodology shown in this paper include: The validated model can be used to determine the maximum drawdown for the onset of sanding.The combined use of flow units and mechanical properties can help avoid zones that are prone to mechanical collapse.Unwarranted sand control operations like gravel packing can be avoided, thereby optimizing field productivity and hence profitability.
Matrix Acid Stimulation - A Review of the State-Of-The-Art
Authors: Rae Phil , Di Lullo Gino 
Published: December 2007

Abstract
Acid stimulation of oil and gas reservoirs, with a view to increasing well productivity, has been applied since the late- 19th century. Initially applied in carbonate reservoirs, the technique was extended to more complex mineralogies, over a number of years. However, it's fair to say that acid stimulation of wells is the exception rather than the rule. This probably stems from the complex, heterogeneous nature of formation minerals and the unpredictability of their response to conventional oilfield acid formulations. With inappropriate acid designs, or poor job procedures, even the best candidate wells can be damaged, sometimes irreversibly.
This paper discusses the current state-of-the art in matrix acidising and makes the case for the wider implementation of acidising, as a cost-effective method for production enhancement. It reviews the many rules used today in the design of acid treatments and how these rules have evolved with improvements in our understanding of the interactions between acids, formation constituents and well tubulars. The paper also reviews the rationale behind the use of additives such as corrosion inhibitors, iron control agents, clay control additives, surfactants, solvents, anti-sludges and diverting agents, etc. and makes general recommendations on appropriate loadings, where applicable.
Finally, the latest developments in acidising are considered, including the use of novel acid systems, to overcome many of the problems inherent in earlier formulations. Innovative equipment design, coupled with real-time monitoring capabilities, improved placement techniques and environmentally-friendly materials, are helping to transform acidising into a valuable asset in the quest for optimum performance from every oil and gas well. The paper references many key publications and provides the engineer with an up-to-date overview of the state-of-the-art in this very important discipline.
Effect of Capillary Cross-Flow on Foam-Induced Diversion in Layered Formations
Authors: Nguyen Quoc P. , Currie Peter K. , Zitha Pacelli L.J. 
Published: December 2007

Abstract
Foams have been widely used to control fluid mobility in improved oil recovery as well as in near-wellbore production enhancement operations, such as acid diversion. The efficiency of fluid blockage and diversion depends strongly on the geological layering of the formation and on the occurrence of capillary cross-flow. However, these effects have not been studied in detail in the literature. In this paper, we report an experimental study of foam-induced fluid diversion in isolated and capillary-communicating double layer cores. Natural rocks were used to manufacture concentric double layer cores, having final permeability contrasts in the range of 10-200. We also used capillary-communicating double layer cores, obtained by sintering two homogeneous glass bead layers. In addition to pressure drop monitoring, the in-situ fluid saturation was visualized using X-ray computerized tomography. A range of foam qualities has been investigated.
Successful Application of Combining Extreme Overbalance Perforating and Alcoholic Retarded Acid Technique in Abnormal High Pressure Gas Reservoir
Authors: Wang Xugang , Zou Honglan , Shan Wenwen , Zhang Fuxiang , Kang Jianli 
Published: December 2007

Abstract
This paper will present the development of the combined extreme overbalance perforating (EOBP) and alcoholic retarded acid technique that shows promise of resolving severe formation damage problems that caused by drilling mud leak off especially in abnormal high pressure sandstone gas reservoir with natural fracture. A new alcoholic retarded acid system is presented in this paper that is stable up to 275°F, highly retarded, and significantly less surface tension than straight acid. Laboratory data comparing alcoholic retarded acid with straight acid are shown at temperatures ranging up to 275°F, including core flow tests and Environmental Scanning Electron Microscope (ESEM) observation.
The method was used to remove most of the previously identified skin damage formation of an exploratory gas well in the TARIM Oil Company in TARIM Basin, China. It has proven that it can offer a cost-effective, safe method when used as a near wellbore clean up and maximize the production of gas well. The skin damage had been reduced to 18 from its original 156. The positive effects from using the combined technologies include: Savings in well testing time and cost of additional stimulation jobs to flow the well had traditional procedures been used. A significant increase in the gas production from an original estimated 200,000m3/d to 1,160,000 m3/d. These facts will be evidenced by the case history experiences disclosed in this paper.
Well Abandonment in the Los Angeles Basin: A Primer
Authors: Evans B. L. , Sailor R. P. , Santiago E. 
Published: December 2007

Abstract
Due to declining oil production and real estate development, an increasing number of oil wells are being abandoned (or reabandoned) each year in the Los Angeles Basin. This paper summarizes the current requirements of the Department of Conservation's Division of Oil, Gas and Geothermal Resources (Division), the engineering required for a good abandonment, current abandonment practices and some of the difficulties encountered in properly abandoning or reabandoning wells
This paper is considered to be very timely and important as the petroleum industry endeavors to leave oil fields in such a condition that surface development can safely follow.
New Cement System Replaces Mechanical Whipstock Plug
Authors: LaPrade David , Low Nick 
Published: December 2007

Abstract
Mechanical whipstock plugs are often chosen in preference to conventional cement plugs to sidetrack in very strong formations or where a very precise short-radius kickoff is critical, even though the use of downhole tools requires extra time and introduces other risks and concerns to the drilling operations.
In this paper we present a new cement system, based on the optimization of the packing volume fraction (PVF) of the dry blend, which results in a set cement with mechanical properties superior to those of regular cements: compressive strength, impact resistance, and toughness. These cements can be used to achieve the same objectives as a mechanical whipstock plug with less risk and offer potential time savings to the overall operations.
The advantages of this cement system are demonstrated in a field test in which a kickoff plug was successfully set and used to drill a short-radius hole.
Reliable Proppant Flowback Control for Low-Stress, Low-Temperature Reservoirs
Authors: Stephenson Chris J. , Crabb Terry M. , Khachatrian Mikael B. 
Published: December 2007

Abstract
Proppant flowback within shallow wells, as with all wells, can be a significant problem in the oil and gas industry. Under the typical low stress and low temperature conditions found in shallow formations, many of the current products and processes to control flowback often fail or have only limited success. As such, improved or alternative technology and procedures are constantly being sought. One such technology is the development of a deformable proppant for use under low closure stress conditions.
Numerous materials, having typically low Young's Moduli, have been screened and tested under laboratory conditions to evaluate their relative flowback control performance. As a result of this development process, reliable proppant flowback control under low closure stress and low temperature conditions has been obtained. Testing of this new ‘low stress’ (LS) deformable proppant, blended with typical fracturing sand, has shown 20 fold increases in flowrate and 10 fold increases in pressure drop are attainable without proppant pack failure, while still maintaining or in some cases increasing fracture conductivity.
Furthermore, this ‘low stress’ (LS) deformable proppant has been applied in wells where other technology has previously been used with limited success. In a number of shallow reservoirs, the addition of this deformable proppant to proppant packs placed during fracturing treatments, has been observed to very effectively control proppant flowback under the conditions of low closure stress and low bottom hole temperature. In order to facilitate field application, new addition and monitoring procedures were developed to accomplish these successful fracturing operations.