bluuebunny/crossref_metadata_2025 huggingface dataset:
Dealing with Russia: A Chinese Perspective
Authors: Huang Yu , Ge Aiji , Xu Xiaojie
Published: December 2007

Russia's opening-up to the outside world has been a great event for the world in general and its neighboring countries in particular. Foreign direct investment (FDI) in Russia started in 1992 and expanded in 1998. Currently, there are 26 foreign companies from eleven countries active in the petroleum upstream sector in Russia, six of which are international majors including BP-Amoco, Shell, Exxon-Mobil, TotalFinaElf and Texaco-Chevron and the like. Europe and US based companies dominate the foreign investment in Russia. E&P projects totaled 44, which are located mainly in Timen-Pechoran, Sakhalin, Eastern Siberia and Western Siberia, regionally speaking. As the largest neighboring country of Russia, China has not concluded any major petroleum direct investment projects in the country except for oil and gas pipeline to be finally approved. Authors will make quantitative analyses of the FDI in Russia here.

Currently, China imported about 60 million tones of oil in 2001 by the sea lance from the Middle East. Against the growing domestic demand, the single source based route makes China's energy less secure. A search for additional sources from Russia and Central Asia has been emphasized and escalated since the opening up of Russia's energy sector. Beyond the pipeline transportation, China is continuing to seek for major undeveloped oil researves, oil pipelines associated projects, along with business alliance through privatization or M&A activities. There are huge issues to be tackled, accordingly.

Chinese petroleum companies are negotiating with Russian counterparts on this matter. Results remain less bright because of corporate strategic and cultural differentials. Some oil and gas provisions remain less clear in Russia.

China has learned from the lessons of western oil companies doing businesses in Russia in the last decade. Long lasting procedure of legislative approval and negotiation with local counterparts thereafter disappointed many western companies. Meanwhile, among several obstacles are contractual system and tax arrangements. However, the paper suggest that

The authors suggest that bidding for undeveloped oil fields and the shares of privatized oil companies in Russia are among choices. PSA along with joint venture arrangement are effective ways available for consideration. However, favorable and transparent policies should be prioritized for any success of business in Russia.

International investors have to realize that Russian need for multiple routes and exporting outlets to ship oil and gas to the regional market. However, the primary for Russia and China or others alike is further close work on contractual conciliation and legal and administrative regulations of the oil and gas pipelines.
Judgment in Probabilistic Analysis
Authors: Purvis D. C.
Published: December 2007

The chief use of probabilistic methods is to assess risk and opportunity, making them most applicable to situations of significant uncertainty. Hence, the cardinal sin unique to probabilistic analysis is to underestimate the range of outcomes. Unfortunately, the situations of the greatest uncertainty are also the ones where poor judgment is most likely to create unreliable results and dangerous decisions. The best judgment in probabilistic analysis is that which recognizes the full range of uncertainty by carefully framing the problem and by avoiding pitfalls which artificially reduce the range of results.
A Model to Describe Fugibility
Authors: Erb Terri , Tobin John
Published: December 2007

The "Model to Describe Fungibility" was built as a hands-on educational tool for public use in an effort to illustrate the concepts of fungibility as well as supply and demand related specifically to the energy industry. The need for such a model came as a response to public concern over international issues and their connection to the energy industry. This visual representation of the fungible nature of energy provides a more comprehensive understanding of how and why certain actions affect or do not affect global markets. Although extremely simplified, the model clearly illustrates that as long as the world inventory of energy is constant, the origin of the commodity is insignificant to the consumer. Disruption to the quantity and price of an inventory is a direct result of any change to the amount of supply or demand. Thus there is an evident balance between the amount of energy available and the amount of energy consumed. The contribution of "green energy" and the "strategic petroleum reserve" are also considered in the operation of this model. "Green energy" contributes a mere trace of energy to the energy mix and therefore, as the model indicates, becomes virtually indistinguishable as it mixes with the contribution from fossil fuels. As the strategic reserve is used, it is clear that this is a finite resource and is non-replaceable. Altering the flow of water by means of adjusting faucets that represent energy production and consumption is the method of operating this model. Concepts discussed above are visually observed in an effective manner. The model is appropriate for all audiences ranging from elementary school children to government officials.
A Discussion on the Effect of International Fiscal Regimes on Portfolio Selection in the Petroleum Industry
Authors: Back Michael J.
Published: December 2007

The corporate planner in an international petroleum company is faced with the difficult task of comparing potential investment opportunities across different geographic and fiscal regimes. The economics in many global fiscal regimes such as production sharing contracts (PSC) requires advanced modeling capabilities, iterative calculations and consolidated economics at a field or block level for appropriate accuracy. This process can be both computationally intensive and nonlinear in nature requiring a recalculation of each proposed portfolio including any delay and working interest factor applied to each project in the portfolio.

This paper will review and compare the effects of several typical international fiscal regimes with both traditional project ranking and more modern portfolio management techniques used in the exploration and production (E&P) capital investment process. The ability to use sophisticated optimization algorithms while achieving maximum computational efficiency and economic accuracy will be explored. The effects of stand-alone vs consolidated project economics at a PSC level will be discussed as well as key issues associated with using portfolio management to compare assets in a variety of fiscal regimes. A personal computer will be used to model several typical international fiscal regimes and analyze a set of petroleum assets in the context of choosing an optimal corporate portfolio.
Analyzing the Sensitivity of Production Sharing Contract Terms Using Simulation
Authors: Mudford B. , Stegemeier D.
Published: December 2007

Fiscal regimes, such as production sharing contracts (PSC's), specify how hydrocarbons and costs are shared between host governments and contractors. An important part of the economic analysis in any new country or region involves modelling the fiscal terms for that area and determining the value of a new opportunity. In most cases there is uncertainty in the technical components of an opportunity. In addition, there may be uncertainty in fiscal terms since they could be open to negotiation. In either case it is necessary to analyze the fiscal regime under conditions of uncertainty.

Most PSC's are composed of royalty, cost recovery, profit split and taxation components. In older PSC's profit splits between the government and the contractors were often based on quantities such as oil production. More recently it has become common to base profit splits on measures of profitability such as the ratio of costs to revenue, or the rate of return. In this paper we will analyze and compare PSC's in several countries, assuming similar-sized discoveries in each country. Our analysis will include both technical uncertainties around volumes and costs, and fiscal regime and price uncertainties. These simulation techniques can be used to establish thresholds for volumes or costs that will enable an economic development to be carried out. In essence thresholds represent lost value in a project, which can manifest itself in projects not done or redevelopments not carried out. It is to the benefit of all parties to try and minimize that lost value. The simulation methods we will outline can be used to determine the fiscal terms that maximize value for both host countries and contractors where these terms are subject to negotiation. These methods can also be used to estimate the value of tradeoffs made during fiscal regime negotiation.
There is Value in Operational Flexibility: An Intelligent Well Application
Authors: Han John T.
Published: December 2007

Intelligent well completion technology provides a broad spectrum of value generating functionality for oil and gas field operations, all derived from the ability to monitor and control fluid production and injection by zone in real-time. A major barrier to intelligent well technology adoption has been the lack of method to quantitatively define the value associated with various applications of the technology. Most companies often use a Net Present Value (NPV) analysis to quantify and rank project proposals. Due to the nature of intelligent well technology, NPV analysis is not applicable to a wide range of applications and invariably underestimates the value associated with the technology. Operators intuitively understand the benefits of the technology, but are unable to represent it with conventional NPV valuation techniques, and thus are unable to justify intelligent well completion deployment against more conventional, better-understood, but lower valued, completion technology.

An approach has been developed to define and solve the intelligent well valuation problem using mathematical techniques from the financial community called Real Options analysis, specifically, the concept of Flexibility Options. It quantifies the option value derived from the flexibility offered by the application of intelligent well technology enabling the ability to monitor and respond to reservoir uncertainties as it is manifested throughout the field life cycle.

Case study has been developed using well data from field in the Gulf of Mexico region incorporating the level of smartness, the associated system reliability, and the projected reservoir performances to quantify the flexibility option value offered through the implementation of intelligent well over conventional completion technology.

This paper will support the conclusions that application of field proven intelligent well technology can increase asset value. The case study use intelligent well critical variables to quantify the value of operating flexibility derived from implementing intelligent well technology. However, some important points should be considered. Firstly, equipment reliability is vital in the valuation. Secondly, economic justification including option value is required to assess the business case in face of reservoir uncertainties. Thirdly, the relationship between resolving reservoir uncertainty, system reliability and functionality must be understood to realize "The right level of Smartness…"
Methodology for Field Development Optimization with Water Injection
Authors: Schiozer Denis J. , Mezzomo C. Christina
Published: December 2007

Field development planning comprises a very complex decision making process. Due to the restricted amount of information available in this initial stage, a great amount of parameters must be estimated and analyzed to propose an adequate and profitable recovery strategy. Therefore, it is very important to develop fast and flexible methodologies with a low computational cost that into account the uncertainties related to economic circumstances to assess the risks in the decision making process.

This paper shows a new approach applied to field development planning with horizontal wells using reservoir simulation to provide coherent production/injection forecasts for the field performance assessment. In order to achieve good quality solutions, different financial scenarios must be included in the optimization procedure, regarding constraints previously imposed to the project. An economic sensitivity analysis is performed to evaluate the influence of the dynamic behavior of parameters like oil price and interest rates in the results obtained with this methodology. The procedure is applied to some selected cases with different natural drives and the results obtained will be presented.

The proposed methodology does not offer a unique solution, but a set of good alternatives to be analyzed by the management. It helps the management to identify field recovery alternatives that are less affected by changes in the economic scenario thus presenting lower risk. The procedure is fast, requiring an adequate number of simulation runs and can be easily adapted according to the characteristics and restrictions defined for each project. It can also be automated to reduce the global time required for the process.
Comparison of LNG Contractual Frameworks and Fiscal Systems
Authors: Kellas Graham
Published: December 2007

abstract

There is an increasing number of competing existing and potential suppliers of liquefied natural gas (LNG) (Fig. 1). Which of these projects will succeed, in large part, be determined by their price competitiveness.

Many factors in the derivation of the minimum, or breakeven, price for an LNG project are driven by technical and logistic considerations - however, the price also needs to be sufficient to cover government taxation and other fiscal impositions at different stages of the project.

The fiscal arrangements for LNG projects are often complex and misunderstood and this paper includes a review of contractual and fiscal arrangements for existing LNG projects and certain proposed LNG projects worldwide.

Particular attention is paid to the different terms applicable to upstream and downstream components of each project and how transfer prices and the fiscal "ring fence" is established.

Finally, the paper discusses the impact of both existing and possible fiscal incentives and considers the role of the Government Take in determining breakeven LNG prices for a number of existing and potential LNG projects.
Economic Model for Gas-to-Power Project Capitalization in Developing Economy
Authors: Osaghae Ephraim Osagie
Published: December 2007

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

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

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.
Field Experience with Composite Coiled Tubing
Authors: Feechan Michael , Makselon Chris , Nolet Stephen
Published: December 2007

Composite Coiled Tubing (CCT) has been field tested on a number of applications with generally good results. This paper will summarize these field experiences and how the tubing has been improved from early versions to the latest product.
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

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

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

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

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

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

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

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

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

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

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

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.
Useful Techniques for Evaluating Facility Expansion Projects
Authors: Dunn M. D. , Seck K. A.
Published: December 2007

Facility expansion evaluations are often performed when reservoir capacity exceeds the design limits of the installed facilities. In most cases, these evaluations are multifaceted and involve several engineering and operations disciplines. The inter-relationships between reservoir performance, pressure drop, process capacities, and operational assurances are not easily resolved. Consequently, the assessment of all scenarios and the identification of the optimal facility modifications require a proper systems approach. Otherwise, the proposed re-configuration of the facilities can deliver much less value than predicted.

This paper discusses a methodology that can be used to properly structure a facility expansion evaluation. Included is a work breakdown structure of fourteen steps. The paper also outlines several techniques and models to describe reservoir performance, illustrate cost versus capacity, screen solutions, and select the optimal project(s) for implementation. One technique is the use of "step change plots" to illustrate expansion options in terms of cost vs. capacity. An analytical based reservoir model has been developed to represent reservoir flow as a function of surface pressures. A pipeline model has been developed to predict pressure drops of various infield pipelines. A facility process model is used to identify bottlenecks and estimate process flow rates under different facility configurations.

The application of the methodology and the prescribed techniques reinforce a systems perspective to the evaluation so that tradeoffs and alternatives can be considered within the context of the overall business objective. It allows the evaluation team to discover the optimal solution and to distinguish the negative impacts of a narrow set of criteria. This paper will benefit reservoir engineers, process engineers, facility engineers, and operations personnel who are faced with the difficult task of evaluating the value of a facility expansion.
Selection, Operation, and Evaluation of High Temperature Oil in Water Monitor for Two-Phase Extra Heavy Oil (Bitumen) Test Separator Service at Peace River
Authors: Geneau Micheal D.
Published: December 2007

Since 1986, Shell Canada has been using two-phase separators for well test application in bitumen production service. As bitumen (8 to 10 API) at Peace River has a density similar to that of produced water, depending on operating temperature, the use of three-phase test separators is not practical. In bitumen service, a three-phase separator requires either heating or cooling plus diluent to reduce the bitumen density so that classical gravity separation can be achieved.

With a two-phase system, a means is required to determine the amount of oil in the produced emulsion. This is often achieved by either obtaining a representative fluid sample from the separator and determining the water cut in the lab, or by an online instrument. The two-phase well test system operates at temperatures ranging from 80 to 200 °C at an operating pressure of 1500 kPa. The water cuts from the wells range from 10 to 90 percent with an average of 40 percent. Agar's OW-201 water-cut monitors, in conjunction with Coriolis mass flow meters, were selected for test separator systems at Peace River.

This paper describes the field tests performed to verify the Agar OW-201 meter operation for Peace River service, Shell's operating experience to date and the performance achieved during one year of operation.
Design and Implementation of a High Rate Acid Stimulation through a Subsea Intelligent Completion
Authors: Bellarby Jonathan E. , Denholm Allan , Grose Trevor , Norris Mark , Stewart Adrian
Published: December 2007

The Machar field is primarily a naturally fractured chalk reservoir; with the subsea wells requiring acid stimulations in order to be economic. This paper describes the design and implementation of an acid stimulation for a new intelligent well completion. The combination of a subsea development, a high rate boat based acid stimulation and a surface operated intelligent completion provided several challenges.

The stimulation challenges arose due to the long reservoir completion and the required use of flow control valves with small tubing within this section. This prevented the traditional use of ball diverters in order to effectively treat the whole reservoir interval. By using the isolation capabilities of the intelligent completion, several intervals were sequentially treated. Within each completion interval, limited entry perforating provided the method of diversion necessary to effectively treat each perforation. In order for this to be successful, the perforations had to be centralised and shot prior to running the completion. Limited entry perforating therefore required physical gun shoot tests and a pump test through the shot holes. The results and conclusions of these tests are included in this paper.

The completion challenges related to the stimulation included assurance of the integrity of the sensitive downhole electronics and hydraulics required to operate the downhole valves and sensors. This assurance was vital as, for the first time with an intelligent completion, the stimulation involved pumping concentrated hydrochloric acid down the well at rates of up to 50 bpm.

Implementation of the stimulation was achieved with the real time multizone downhole pressure and temperature data providing several fascinating opportunities to view downhole mechanisms. Of particular interest is the pressure transient impact of a stimulation on adjacent zones and the cooldown effect on partially trapped annuli. The analysis of this downhole data is presented.
Drilling Facility Design - "A Wells Up Approach"
Authors: Nichols John , Lawrie Kenny , Jenkins Paul , McGill John
Published: December 2007

There are a number of developments where new dry tree platform drilling rigs are specified. In some cases the geographical location, number of wells to be drilled and the ongoing life of field intervention requirements lead to the need for a permanent rig installation.

The majority of permanent offshore rig installations has in the main been confined to the N. Sea region. As a result there is a significant experience base related to how the rig interfaces with the production platform and the lessons learned from operations that can be used to ensure appropriate drilling facilities are designed.

Compared to the overall project or field development cost the initial capital cost of the rig is usually a relatively small proportion of the project. However, when the operational cost of drilling and maintaining the wells is included it can account for between 30 - 40% of the overall development costs. Therefore the actual operational efficiency of the rig will have a significant impact on the overall project economics.

During the initial stages of a project it is essential that the project requirements such as the regulatory requirements, well designs, platform interfaces and philosophies and the appropriate levels of mechanisation are understood. This allows a clear definition of the rig equipment selection and functionality to ensure the rig is not over or under rated in order to allow the drilling team to provide a rig that delivers the expected operational efficiency.