bluuebunny/crossref_metadata_2025 huggingface dataset:
New Method To Read and Correct the API Gravity of Oil From Observed Temperatures to 60°F (includes associated paper 28944)
Authors: Keaves Sonny V.
Published: June 2014

This graphical interpolation method is plotted directly from the American Soc. for Testing and Materials (ASTM) tables. The method, a one-step procedure and direct reading, is easy and quick. It is difficult to make errors. No calculations are involved, which is not the case for the method described in the ASTM manual. The usual calculation method can easily and frequently cause errors, and few enjoy consulting the manual to do the calculations for checking. If you have not used the calculation method in a while, you probably will need to review the instructions and examples again. Taking the time to do so is difficult when you are busy.

The graphic chart in Fig. 1 is one of many I created on a PC to describe the new method. Remember, API gravity is measured from 0 to 1000API and from 0 to more than 150°F (ASTM tables stop at 150°F). If one chart contains 20 curves from 0 to 75°F, a total of approximately 10 charts will be needed to cover the full temperature and API ranges.

The following examples show how to read the chart.

Example 1. (Same information as Example 1 in the ASTM manual, Appendix C.) Find the API gravity at 60°F for 38.400API at an observed temperature of 76°F.

Solution. Enter the 38° API line down to the observed temperature of 76°F, divide the distance from this line to the next line above it by 10 (each division is a 0.10), mark 0.40 on that scale and add 38 to make 38.40, and then read directly from there. Point A is 37.200API at 60°F of the 38.40° API at the observed temperature of 76°F.

Example 2. Find the API gravity at 60°F for 41.50° API at an observed temperature of 79°F.

Solution. Enter the 41.00° API line down to the observed temperature of 79°F. Repeat the next step from Example 1. You will find that the API gravity at 60°F for 41.500API at 79°F is 40.000API, which is Point B.
Realising The Benefits Of Environmental Risk Management
Authors: Holgate M. , Mentzer E. , Garnham P. , Harris E. , Davies G. , Verburgh J. , Whitehead A. , Shepherd J.
Published: June 2014

The E & P industry is facing increasing costs from meeting its environmental responsibilities. European governments have collaborated with the industry to develop a harmonised scheme to model the environmental hazard of production chemicals.

It is proposed that the model be incorporated into a cost benefit analysis to prioritise environmental solutions. This opens the way for a goal setting regulatory framework as a means of targeting resources to achieve real environmental gains.
Production Enhancement Partnerships - Successful Business Arrangements
Authors: Coble Larry , Weitzel Kenneth , Attai Larry , Gray Kent
Published: June 2014

Production enhancement projects are creating changes in business relationships between oil & gas and service companies. The most successful projects are building partnerships. Service companies are being asked to share the risk while supplying services to enhance well performance. Risk sharing creates common project objectives and requires the service company's involvement in initial project planning, job design, and reservoir understanding. Service work compensation is based on well or field performance improvement as a result of the treatment(s).

This paper presents an integrated approach to the selection and prioritization of well candidates for production enhancement jobs or treatments. Special emphasis is placed on reservoir understanding using field reviews and/or extensive reservoir description studies to provide the essential information for well candidate selection and the best return on investment. Processes are illustrated and discussion gives the data requirements and techniques used to select and prioritize well candidates. Field examples demonstrate the techniques, critical factors, and appropriate software used by geoscience and field operations teams to maximize benefits from production enhancement projects.

Introduction

The need for a better business arrangement with service companies has been identified by many operating companies. Partnerships evolved to align interests, utilize the same performance measurements, create an environment for teamwork, ensure use of appropriate technology and add value by increasing the project profitability.

The bidding process is being replaced with partnerships due to the realization that superior benefits can be obtained. In the typical ‘low bid’ scheme, the operator planned the project, designed the job and distributed the job specifications to several suppliers to bid the services and materials. In many cases, the operating company would select the vendor supplying the work based on the lowest price. This type of arrangement gave little incentive to the service company to enhance production. If the job went as designed, i.e., the service company was on time, brought the necessary materials, and performed the job within the specifications, the service company considered the job a success. However, the job may not have achieved the expected production increase for the operating company. Project profitability and continuous quality improvement can be compromised in this scenario.

The alliance/partnering business arrangement is an excellent vehicle to achieve continuous improvement and apply ‘best practices’ techniques.
Environmental Mandate Reform
Authors: White Ronald D. , Russell Barry
Published: June 2014

America's current system of establishing environmental mandates treats the concepts of a healthy environment and a strong economy as if they are mutually exclusive. Certainly a cheap, reliable source of domestic energy does not appear to be a high priority. A balance must be returned to the system by improving the governmental processes of risk assessment, risk management, and risk mitigation.

This paper describes the shortcomings of the current system and outlines the impact of the problems. Proposed improvements to the risk process are discussed along with possible implementation strategies.
Test Method for "Actual" True Vapor Pressure of Crude Oils
Authors: Henderson J. K.
Published: June 2014

Currently, the "True" vapor pressure of crude oil is typically calculated via API 2517 temperature nomograph adjustments to Reid Vapor Pressure testing results (ASTM D-323-90). This "True" vapor pressure or simply vapor pressure for a given oil or fluid is of interest because it defines the point of vapor initiation (i.e., the boiling point or bubble point). The quantity of such oil vapors is of course directly related to product losses and environmental air emissions. It has been found that the Reid test even with the API 2517 adjustment for "True" vapor pressure gives 50% to over 300% errors in the determination of a crude oil's actual true vapor pressure.

Mitretek Systems, therefore, developed a test method with calculation algorithm that substantially improved the determination of a crude oil's "actual" true vapor pressure. The method involves use of a device to 1) analyze the composition of gas separating from a liquid oil stream at a known pressure and temperature, 2) measure the rate of gas and oil flow exiting the same gas/oil separator, and 3) use the described test data in an iterative calculation algorithm with industry-established gas/liquid equilibrium values to estimate the crude oil's vapor pressure within +/−2% (or 0.3 psia). This test method provides a characterization of the oil's composition which then allows prediction of vapor pressure as well as air emission quantities over the full temperature range of interest. In addition air toxics existing in the oil (H2S, benzene, etc.) have been quantified to the 10 ppm level in the oil as well as in the evolved gases.
Modelling and Operation Optimization and Flow Control of Large Scale Water Injection Systems
Authors: Miaoxin Chen , Yubo Duan , Congxin Li , Guangyu Si
Published: June 2014

This paper presents a new method for modelling and operation optimization of large scale water injection systems. Systems of tms Kma usually consist of a great number of water injection stations.pipelines.valves.pipe fittings,and water injection wells, and is a multi-source multi-sink nonlinear time-vaiying system with thousands of vanables. A properly simplified and sufficiently accurate mathematical model lias been made by both the analytical method and the system identification method. A new operation optimization method has been developed for this system by the large scale system theory and the dynamic programming method To solve this optimization problem.the concept of pressure valley in hydrodynamic system is presented for the first time in this paper. The water uniection system is divided into a senes of subsystems according to pressure valleys It has been proved 1 that system optimization on the whole is equivalent to optimization of every subsystem in it if coupling variables of the subsvstems have the values resulting from the optimized system. Thus, rhe system optimization problem is decomposed into a senes of subsystem optimization problems.

The above modelling method and operation optimization procedures are programmed in a software package. This package has been applied to an oilfield in Daqing Electnc power consumption for water injection decreased by 3- 10%,and waterflood efficiency improved.
Application of Well Test in Daqing Oil Field
Authors: Yongsheng Chen , Yaozu Wang
Published: June 2014

Well testing methodology was modified for Daqing field to account for the case in which rows of wells are brought on production and injection. Other applications of well testing are given including analyzing the effectiveness of fracturing, and detecting distortion of casing in a water injection well. An example is given of using well tests to evaluate the effectiveness of a lime suspension treatment to plug a large channel. Examples are also provided of how interference tests were used in conjunction with tracer testing to evaluate inter-well communication and fracture direction.
The Logging Technology for Determining Production Profiles Through Casing/Tubing Annulus in Pumping Wells
Authors: Zhang Baoqun , Zhang Shuying , Wang Baochun , Zhang Weiping
Published: June 2014

Logging technology for determining production profiles through casing/tubing, the small diameterseries of designing tools, and the advanced logging techniques is described. Applications of the logging technology are demonstrated using typical examples.
Experimental Investigation on the Dielectric Constant of Rocks with Low Porosity and Permeability
Authors: Weinan Wang , Xi Zhang , Xiuwen Geng , Qingzhen Chang
Published: June 2014

Relation between the dielectric constant of rocks, sampled from the western exploring area of Daqing Oil Field, and water saturation, salinity is developed. Effect of shale and water distribution on the dielectric constant is discussed through experiments on artificial core samples and shale samples. The mixing law that describes the relation between dielectric constant and water saturation is revised and a new one characterized by the area is proposed.
The Logging Technology for Determining Water-Intake Profile With the Radioisotopic Carriers
Authors: Niu Chaoqun , Qiao Hetang , Chen Shiduo , Chen Xiaohua
Published: June 2014

The logging technology of radioisotopic carriers has long been a main means to monitor and survey injection profiles in during water injection. This paper focuses on the basic principles of the logging technology, radioisotopic microballs, logging tools, auxiliary equipment, logging techniques, data interpretation, and application effects.
Methods and Effects of Cyclic Waterflooding in the Southern Oilfields of Daqing Placanticline
Authors: Zhongrong Li , Xianzhi Shao , Yongsong Qiu , Xuezhong Chen
Published: June 2014

The paper summarizes the methods and effects of cyclic waterflooding in the southern oilfields of the Daqing Placanticline, discusses the feasibility and necessity of this process in lower permeability reservoirs, and analyzes systematically the main factors which impact the results of cyclic flooding. Production performance is compared and contrasted for fields developed by both conventional, and cyclic waterflooding. Based on field case histories, the impact of cyclic waterflooding on performance at different water cuts is evaluated. It is demonstrated that cyclic flooding should be implemented at low water cuts, but is beneficial at all development stages. Cyclic waterflooding is an effective measure to enlarge sweep volume and enhance conformance efficiency and oil recovery. The practices described can provide guidance for cyclic waterflooding in similar oilfields.
Major Technical Measures To Increase The Recoverable Reserves Of Large Heterogeneous Sandstone Oil Fields
Authors: Demin Wang , Chengzao Jiang , Yingjie Sun
Published: June 2014

Daqing Oil Field is the largest oil field in China and one of the largest oil fields in the world. Development began 35 years ago. By cyclic identification and comparison of continental heterogeneous sandstones, studies on sedimentation models and sand body types, a better understanding of the development stage, water flood characteristics and residual oil distribution of different types of sandstones was obtained. A whole set of technologies (including geology, reservoir engineering, drilling, production, open hole logging and production logging) were developed to increase the recoverable reserves of different zones. As a result, at each stage of development the recoverable reserves of the oil field were increased. It is estimated that after drilling the third round of infill wells and after polymer flooding, the recoverable reserves will be 118 to 133% higher than 1978. Daqing was brought on production in 1960. The present water cut is around 80%. Production reached 50 × 106t in 1976 and in 1995 reached a record high of 56 × 106. Production has been stable for 20 years and is estimated to be stable for another long period of time. Excellent development results have been obtained and are better than planned.
Planning a Dynamic Kill
Authors: Abel L. William
Published: June 2014

This article discusses the methodology, design philosophy, and guidelines for planning a dynamic-kill operation for a wild well. The topics covered are two methods of computer analysis for designing dynamic-kill requirements, the design process, determining the pumping spread, and the pitfalls that a designer faces in planning a dynamic kill.

Introduction

The dynamic kill of a blowout involves pumping fluid through a conduit (a relief well, snubbing string, or drillstem) to stop the blowout and kill the well. Fig. 1 shows a typical scenario for a relief well. While dynamic kills are sometimes accomplished by pumping down a conduit that is in or snubbed into the well, this application is limited because the bore of the conduit restricts the pumping rate. In a dynamic kill, the blowout well is overcome by the combination of increased hydrostatic and frictional pressures in the wellbore. A common misconception is that the friction component is the major factor. Field results and computer models that account for two-phase flow show that the blowout well can be killed more readily by introducing a high-density fluid into the wellbore instead of pumping at high rates to generate frictional-pressure losses. Therefore, the most cost-effective dynamic-kill solution will generally involve pumping dense mud rather than water or other low-density fluids.

The kill fluid and pumping design must account for many factors, including leakoff, formation fracturing, and reservoir parameters. Many times, these values contain uncertainties that must be dealt with in the analysis. However, the single most important factor is the increase in hydrostatic pressure during the initial kill operations. This occurs as the kill fluid mixes with the blowout effluent and increases hydrostatic pressure in the wellbore. The only exception is the underground blowout. In some underground blowouts a reactive material that generates high frictional pressures can be used to generate a "friction" kill instead of a hydrostatic kill. This is true under only a very limited number of underground blowout conditions.
Depletion Performance of Gas-Condensate Reservoirs
Authors: Raghavan Rajagopal , Jones Jack R.
Published: June 2014

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

Introduction

This paper reviews basic methods for evaluating the depletion performance of a well producing a gas-condensate fluid. In particular, we discuss initial gas-in-place estimates, inflow-performance relationships, the development and behavior of liquid saturations over both time and drainage area, and the interpretation of pressure-transient tests. Every aspect of these calculations for depletion of a gas-condensate, or any other essentially two-phase system, is implicitly dictated by the interaction between the fluid properties of the initial gas-in-place and the relative permeability properties of the reservoir rock. The simple steady-state theory forms a useful framework for understanding these interactions and often yields practical approximations for some important quantities. This theory and its relationship to commonly available laboratory measurements form the foundation for many of the methods discussed.

Fluid Determination, Properties, and Descriptions

Classification of a reservoir fluid as a black oil, volatile oil, gas condensate, wet gas, or dry gas is important because application of appropriate engineering practices to predict reserves and rates traditionally requires this knowledge. Fig. 1 is a schematic of a pressure/temperature (p-T) diagram for a multicomponent hydrocarbon mixture of constant composition. The region inside the envelope formed by the bubblepoint curve, critical point (C), and dewpoint curve is where liquid and vapor exist in equilibrium. Lines of constant liquid volume are shown inside this region. Fluids initially at temperature and pressure Positions I through V would be classified as a black oil, volatile oil, gas condensate, wet gas, and dry gas, respectively. Gas condensates are separated from the other fluid types by two characteristics: the condensation of a liquid phase at reservoir conditions during isothermal depletion and the retrograde (revaporization) nature of this condensation. Retrograde behavior of the condensing liquid phase can be seen by tracing the change in liquid volume along the constant-temperature line beginning at Point M in Fig. 1. After crossing the dewpoint line, the volume of liquid increases to approximately 10%at Point N and then begins to decrease with continued reduction in pressure.
X-Ray Computer-Assisted Tomography for Laboratory Core Studies
Authors: Hicks Paul J.
Published: June 2014

Introduction

X-ray computer-assisted tomography (CT) entered the petroleum scene about 13 years ago. The technology showed much promise, but was expensive, unproven, and inaccessible to most petroleum engineers. Today CT scanners are an integral part of most major oil company, service company, and research university laboratories. This paper gives an overview of the theory and typical applications of CT.

Theory

Although CT is used to determine a wide variety of oilfield rock and fluid properties, it measures only one property, the linear attenuation coefficient, µ. The linear attenuation coefficient is defined by Beer's law and is a measure of the fraction of X -rays that pass through an object.

Applications

CT measurements are nondestructive and relatively fast. Most petroleum applications are aimed at estimating lithology, porosity, and/or saturation. By conducting well-designed experiments, these three parameters can be used to obtain a wide variety of additional information. When plugs are to be taken from whole cores, the whole core can be scanned beforehand, enabling the plugs to be taken at appropriate locations. This can be done without removing the wrappings for preserved cores.

Lithology and Porosity. Lithology determination is typically performed for one of two reasons. The first is the screening of cores. Cores are used in a wide variety of laboratory flooding experiments. Even if CT is not used during the flow experiments, it is a useful tool for selecting cores for these experiments. Flooding experiments can be expensive and time consuming, and their analysis typically involves an assumption of uniform porosity and/or permeability. Little is more disheartening than spending months on a project only to find that your analysis is suspect or wrong because a supposedly homogeneous core has a significant interior shale streak or other heterogeneity, unnoticed from the outside. Today, many samples are routinely CT scanned to check qualitatively for homogeneity before conducting coreflooding experiments. This should be standard procedure.
Design and Installation of a Cost Effective Completion System for Horizontal Chalk Wells Where Multiple Zones Require Acid Stimulation
Authors: Thomson D. W. , Nazroo M. F.
Published: June 2014

An innovative completion design that allows multiple acid fracs to be performed in horizontal subsea chalk-formation wells with a single trip into the wellbore has recently been codeveloped by a major North Sea operator and an oilfield engineering/manufac-turing/service company. The project was initiated to develop a system that would allow multiple acid stimulations to be efficiently performed in the shortest possible time in the North Sea Joanne Field. The system ultimately developed allows acid stimulation of up to 10 different zones in a single trip with no through-tubing intervention. The first well in which this new technique was used had 7 zones, and 3 additional wells with 10 zones each were later completed. The development of this system and case histories of the first four subsea wells requiring stimulation will be presented in the paper.

The key element of the system is a multi-stage acid frac tool (MSAF) that is similar to a sliding sleeve circulating device and is run in the closed position. Up to 9 MSAF tools can be run in the completion with isolation of each zone being achieved by hydraulic-set retrievable packers that are positioned on each side of an MSAF tool. Each sleeve contains a threaded ball seat with the smallest ball seat in the lowest sleeve and the largest ball seat in the highest sleeve. With this system, stimulation of 10 separate zones is accomplished in 12-18 hours by a unique procedure that lubricates varying sized low-specific gravity balls into the tubing and then pumps them to a mating seat in the appropriate MSAF, thus sealing off the stimulated zone and allowing stimulation of the next zone which is made accessible by opening the sleeve.

This technique provided a substantial reduction in the operational time normally required to stimulate multiple zones and allowed the stimulations to be precisely targeted within the reservoir. The case history data will provide comparisons in operational times between traditional stimulations and this new method as well as the significant enhancements to cost efficiency that resulted from its use. Additionally, this completion method allowed the stimulations to be designed and matched to the requirements of each reservoir zone, which provided the most cost efficient treatments possible.
E&P Technology Transfer: The Key to Success
Authors: Reinart Michael R.
Published: June 2014

Petroleum industry technology has historically been transferred in very conventional ways. The technology-transfer methods used most often were reading printed materials, attending schools or conferences, and transferring personnel. These methods are effective but time consuming and costly. Transferring technology through activities that are embedded in the person's job is becoming common. The benefits of simultaneous learning and applying that knowledge are significant. Many people and organizations have struggled with their ability to disseminate new technology and apply new techniques. Improving the cost effectiveness of technology transfer will help many E&P companies be successful in the future. Companies that continuously improve their technology-transfer process will capture more growth opportunities.

Background

For a significant part of the petroleum industry's early history, technical information was shared through print media, formal training, and personnel movement. These techniques required a strong commitment of personnel time and were adequate until now. Slim product margins and competition have forced technology-transfer methods to become more efficient.

The assortment of printed information available to the technical professional is enormous. Libraries and offices are full of textbooks, technical papers, monographs, and technical manuals. Many of the latest technology advancements are well documented in the literature. In today's environment, even dedicated professionals simply do not have the time to keep up with the large number of books, journals, and papers that are being published.

Many engineers and geoscientists will attribute much of their technical learning to attending schools and conferences. University and industry courses are well-established sources for technical training. Likewise, individuals use industry conferences, symposiums, seminars, and forums as an excellent source for ongoing technology enhancement. Most of these offerings are focused on topics that are critical to the experienced professional. However, these activities are considered by many as expensive and time consuming. For years, the primary focus was on the associated expenses to attend these sessions. However, concern for the time commitment involved has become increasingly important.

Frequent personnel relocations have been common throughout much of this industry's history. Most transfers are motivated by the desire to place the person with the right skills in the proper assignment to meet changing conditions. However, the ongoing reduction of operating expenses has impacted the frequency of personnel relocations. Companies in the E&P industry are now challenged with finding ways to accomplish these same benefits at a reduced cost.
Underground Storage Operations
Authors: Knepper G.A.
Published: June 2014

Technology Today Series articles provide useful summary information on both classic and emerging concepts in petroleum engineering. Purpose: To provide the general reader with a basic understanding of a significant concept, technique, or development within a specific area of technology.

HISTORY AND GROWTH

The underground storage of natural gas, which began on an ongoing basis in the Zoar field, south of Buffalo, New York, in 1916, has grown to become a large and essential part of the natural gas delivery system. Early growth was slow because the industry itself grew at a slow pace. By 1925, only four pools with a total capacity of 7 Bcf were in use. This number increased to 15 pools by 1935, with 39 Bcf of capacity. The late 1930's saw the beginning of significant growth in both the number and capacity of these pools, and 75 pool sand 251 Bcf of storage capacity had developed by 1945. Another 10 years saw these figures more than double to 178 pools and 1,849 Bcf. This post-war expansion continued as natural gas became more widely used and pipeline expansion brought more and more gas into the northeast and other sections of the U.S. where it had not been previously available or where local supplies were declining.

This rapid expansion of storage continued through 1965, with 293 pools and3,942 Bcf of capacity; by 1975, 376 pools were in use storing a total of 6,644Bcf of gas. Expansion has slowed somewhat since then, with approximately 400pools holding 7,800 Bcf by 1990 (Fig. 1). The location of these pools has also spread rapidly, with 27 states now having gas-storage pools. Much of this storage capacity is concentrated near large market areas in the middle Atlantic and north-central parts of the U.S. Storage has also become very important in the Canadian gas industry, which now has more than 30 pools holding 579 Bcf of gas. The facilities required for the gas-storage segment of the natural gas industry are also very significant, with approximately 18,500 gas-storage well sand 350 compressor stations with 1.75 million hp.
Advantages, Costs, and Pitfalls of International Drills and Exercises
Authors: Neilson David E.
Published: June 2014

This paper (SPE 50156) is an edited version of SPE 46743, first presented at the 1998 SPE International Conference on Health, Safety and Environment in Oil and Gas Exploration and Production held in Caracas, 7 10 June. Original manuscript received 24 March 1998. This paper has not been peer reviewed.

This paper analyzes the benefits, financial implications, and potential drawbacks of the oil industry's holding response exercises and drills. The paper gives guidelines on how to maximize the investment in both financial terms and personal effort. In addition, drivers, objectives, and who should do what are discussed. We provide personal experience to show the reader how to avoid problems and overcome issues in development and management of drills internationally.

The paper looks at what is expected in different parts of the world and what really is required for best industry and government preparedness. Changing trends of expectations, requirements, and what really works worldwide are also explored. The scope of industry operations covered in the paper is upstream E&P activities and transportation. Also covered are the effectiveness of the numbers of people involved; innovative use of exercise input; and some low-cost, but effective, options.

Pitfalls that could devalue the drill are also discussed, including such problems as industry and governments not being equally skilled in such issues as response management and the ability to draw on appropriate resources. In certain cases, these problems can defeat the initial objectives of holding the drill. Guidance is also given on how to decide which organizations should be involved in the development and planning phases of the exercise and when they should be involved. Finally, opinions are given on why industry carries out drills, what the benefits should be, whether it is worthwhile, and how well it should be done.

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Real-Time Geosteering in the Tern Field for Optimum Multilateral Well Placement
Authors: Roberts M.J. , Kirkwood A. , Bedford J.
Published: June 2014

The Tern oil field is located in the North Sea and has been producing from Brent Group sands since 1989. Initially, conventional development techniques were used to exploit the Etive Formation which exhibited excellent reservoir characteristics. Since 1995, development focused on the exploitation of poorer quality formations such as the Rannoch and Upper Ness, through an asset based approach to field management. This has realized significant improvements in profitability thanks to deployment of advanced techniques in reservoir definition and exploitation methodologies.

The ability to efficiently exploit sands as thin as 10 ft through multilateral horizontal drilling has led to fundamentally different and improved development opportunities to enhance profitability. This paper describes the Geosteering technology and methodology used for its effective deployment in multilateral well TA16.

At all stages of the operation, a multidisciplinary approach was adopted with close cooperation between operator and integrated service company personnel. Prior to drilling the lateral, detailed computer based geological models were used to define the target in 3D space and to indicate the relative value of logging while drilling (LWD) measurements to the operation. This was achieved by assigning petrophysical properties to each geological layer and convolving the model with appropriate tool response functions along the planned well trajectory. The results of this exercise confirmed the need for a real time porosity measurement for confident geosteering decision making. Consequently a while drilling density neutron tool was included together with resistivity, gamma ray and directional tools to maximize potential net pay rewards in the well.

During drilling, real time LWD data were evaluated by the shore-based asset team and corrective geosteering action taken for observed changes in reservoir quality, dip and sub seismic faults. As a result, the well was successfully drilled in a 10 ft thick oil sweet spot in the Rannoch formation and completed over an 800 ft interval flowing dry oil at rates significantly above plan.

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Integrated Risk Management: The Millennium Key to Sustainable Development
Authors: Smith A.L.
Published: June 2014

This paper (SPE 51006) was revised for publication from paper SPE 46868, first presented at the 1998 SPE International Conference on Health, Safety and Environment in Oil and Gas Exploration and Production held in Caracas, 7 10 June. Original manuscript received 24 March 1998. This paper has not been peer reviewed.

Introduction

Health, safety, and environmental (HSE) risks and their management concern the international oil and gas E&P industry. The main objective of integrated risk management is to contribute significantly to achieving business objectives and thereby provide the key to sustainable development in the next millennium. Risk management is defined as "the process whereby decisions are made to accept a known or assessed risk and/or the implementation of actions to reduce the consequences or probability of occurrence." It is not simply reduction of risk. A more realistic objective would be to strike an appropriate balance at the conceptual stage between benefits from reduced risk, expense of that reduction, and gains from the enterprise. An objective judgment can then be made on how to operate to optimize the level of risk on a day-to-day basis. Some risks, however, are simply unacceptable and therefore not a matter of compromise or optimization. As with all management, risk management is concerned with setting and achieving goals that support overall company or societal goals.

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Well Examination Self Regulation in a Goal-Setting Environment
Authors: King G.W. , Dobson J.D.
Published: June 2014

This paper (SPE 51318) was revised for publication from paper SPE 39381, first presented at the 1998 IADC/SPE Drilling Conference held in Dallas, 3 6 March. Original manuscript received 19 December 1997. This paper has not been peer reviewed.

Safety in the offshore oil and gas industry in the U.K. is now enforced through a system of goal-setting regulations that require companies to set standards, then demonstrate how these are achieved. Within this system, the safety of wells and well work is controlled by a requirement that operators develop and apply well-examination schemes where work programs are reviewed by independent, competent examiners. This paper describes the previously used scheme based on explicit government approval; the relevant elements of the goal-setting environment; and how well-examination schemes have been developed, how they operate, and the impact of well examination for companies working in the U.K.

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To Determine Herschel-Bulkley Coefficients
Authors: Klotz James A. , Brigham William E.
Published: June 2014

E&P Exchange

This article presents a straightforward, accurate method for determining the three coefficients of the Herschel-Bulkley equation from six-speed Fannviscometer data. Within the past several years, the Herschel-Bulkley, oryield-power-law, equation has gained acceptance as a better descriptor of drilling-fluid viscosity than either the Bingham plastic or power-law equations. The Herschel-Bulkley equation has three coefficients. The drilling-fluid literature, however, does not seem to contain a good method for calculating these coefficients from the data points obtained from a Fannsix-speed VG meter.

We present the following equations for making that calculation.

Obviously, such a search can be automated by means of a computer search program. Table 1 and Fig. 1 illustrate results of such a calculation with some of the Ref. 1 Fann viscometer data.

The Herschel-Bulkley coefficients in Table 1 were calculated with Eqs. 1 and2. The curves of Fig. 1 were then calculated with these coefficients. As can be seen, the curves go through data points very well. Where the data are notsmooth enough to be fit exactly with a three-coefficient curve, this calculation method results in a curve that has as many data points above as below the curve.
The Environmental Impact Factor - a proposed tool for produced water impact reduction, management and regulation
Authors: Johnsen S. , Frost T. K. , Hjelsvold Mona , Utvik Toril Røe , Hydro Norsk
Published: June 2014

The Norwegian government issued in 1998 White Paper No. 58 followed by the "Zero discharge report" requiring the oil industry operating in the Norwegian sector of the North Sea to develop a strategy for reaching "zero environmental harmful discharges" of produced water (PW) within 2005. As a result Miljøsok proposed to develop a management tool based on environmental risk and hazard assessment to identify the most potential environmentally harmful discharges of PW, and to quantify the environmental benefit of different actions to reduce these. The Norwegian Oil Industry Association (OLF) working group for PW was asked to develop the Environmental Impact Factor (EIF), and the tool has so far been applied for PW management on a single platform level. The plan is to elevate this work to a regional scale in order to compare the potential benefit of measures to reduce PW discharges in the whole area, and to form a basis for a cost-effective total approach to PW management.

The EIF is based on a combined environmental risk and hazard assessment of PW discharges, accounting for both composition and amount of the discharge. The EIF is also linked to the environmental impact assessment (EIA) studies in the area and the environmental monitoring programme for the water column, initiated in 1999.

Determination of the EIF for a single platform allows the operator to rank the available technologies for PW discharge reduction on a cost-benefit basis. The EIF identifies the source of potential environmental damage and quantifies the benefit of any action taken to reduce this. Technologies like PW re-injection, treatment and removal or replacement of process chemicals can thus be ranked based on cost and environmental benefit.
The Power of Being Public Lessons Learned From a Reversed Merger
Authors: Darden Glenn
Published: June 2014

The late 1990's marked an increase in corporate consolidation, especially in the oil and gas industry. As E&P companies emerged as mega-majors and super-independents were born, the mid-size and smaller independents faced finding creative ways to compete.

In 1998, when the window of opportunity was narrowing for companies to go public, Fort Worth-based Quicksilver Resources Inc. began negotiations with MSR Exploration Ltd. on a reverse merger as a way to become a publicly traded company. In this case, Quicksilver purchased a public company (MSR) for common shares and the stockholders of Quicksilver controlled a majority of the newly formed company's common stock.

Due Diligence

Ironically, Quicksilver's strategy did not start with the intention of acquiring a public company. In fact, the management of this private, closely held family business was simply seeking avenues for growth with all options open for consideration. Quicksilver considered initiating a traditional initial public offering (IPO), but the financial climate for oil and gas companies was stormy. Access to capital was critical and the company was pursuing alliances with larger financing companies. In 1997, discussion over property asset acquisitions eventually led to the boards of Quicksilver and MSR determining that a merger of the two companies would be mutually beneficial. Both companies had contiguous producing properties in northern Montana. Negotiations began in late 1998, at a time when only two oil and gas companies were pursuing traditional IPO's, suggesting that timing wasn't right for Quicksilver to do the same. Quicksilver recognized that the reverse-merger option appeared to be the reasonable, near-term solution for Quicksilver's aspiration for growth, unless the company waited for the cycle to change.
Technology Innovation for Determining Surface Roughness in Pipes
Authors: Farshad Fred F. , Rieke H.H.
Published: June 2014

Technology Today Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

Since 1995, several petroleum companies have actively sponsored research on how internal-surface wall-roughness texture affects the flow of fluids in oil-country tubular goods (OCTGs). The research goal focuses on the development and application of new technologies in combating the effects of pipe corrosion, establishing new piping materials and coatings, increasing the ease of fluid flow in pipes, and validating such improvements. A result of the research is a newly developed surface-roughness correlation for modern pipes.

Introduction

Currently, one area of focus is on achieving infrastructure-cost reductions in the transport of gas and oil through pipelines. Profilometer technology is a good example of one such application that is being adapted from the metal fabrication/manufacturing industry to measure the internal-surface roughness of piping. Internal-surface roughness impedes the dynamic transfer of fluids and is a major factor in the optimization of production tubing and pipeline utilization. Corrosion creates scale and pits along the walls of the piping, which in turn impedes flow and creates a loss of pipewall integrity. Other irregularities result from cutting tools, chatter, abrasive cleaning and preening operations, plating, anodizing, and chemical milling during manufacturing. The roughness of a solid surface is defined as any departure of the actual surface from an ideal datum level known as the nominal level. Surface profiling gauges the ups and downs of a surface, which the human eye cannot discern. The method results in a quick and easy way of calculating the pipe's friction factor. This method is a major step forward in production-tubing and pipeline design. The elimination of expensive and time-consuming flow-loop testing is the most obvious advantage of this technology.
Recent Developments in Application of Artificial Intelligence in Petroleum Engineering
Authors: Mohaghegh Shahab D.
Published: June 2014

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized to be experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

With the recent interest and enthusiasm in the industry toward smart wells, intelligent fields, and real-time analysis and interpretation of large amounts of data for process optimization, our industry's need for powerful, robust, and intelligent tools has significantly increased. Operations such as asset evaluation; 3D- and 4D-seismic-data interpretation; complex multilateral-drilling design and implementation; log interpretation; building of geologic models; well-test design, implementation, and interpretation; reservoir modeling; and simulation are being integrated to result in comprehensive reservoir management. In recent years, artificial intelligence (AI), in its many integrated flavors from neural networks to genetic optimization to fuzzy logic, has made solid steps toward becoming more accepted in the mainstream of the oil and gas industry. In a recent set of JPT articles, fundamentals of these technologies were discussed. This article covers some of the most recent and advanced uses of intelligent systems in our industry and discusses their potential role in our industry's future.

Introduction

On the basis of recent developments, it is becoming clear that our industry has realized the immense potential offered by intelligent systems. Our daily life as petroleum professionals is full of battling highly complex and dynamic problems and making high-stakes decisions. Moreover, with the advent of new sensors that are permanently placed in the wellbore, very large amounts of data that carry important and vital information are now available. To make the most of these exotic hardware tools, one must have access to proper software to process the data in real time. Intelligent systems in their many flavors are the only viable techniques capable of bringing real-time analysis and decision-making power to the new hardware.
Syntheses, characterization and electrocatalytical comparison of two cadmium-containing mono-lacunary Wells-Dawson polyoxometalates, α1- and α2-[P2W17Cd(H2O)O61]8-
Authors: Zonoz Farrokhzad , Jamshidi Ali , Hajizadeh Fateme , Yousefi Khadijeh
Published: June 2014

Two new cadmium-containing Wells-Dawson polyoxometalates
K8[?1-P2W17Cd(OH2)O61]?16H2O (?1-P2W17Cd) and K8[?2-P2W17Cd(OH2) O61]?16H2O
(?2-P2W17Cd) were synthesized as aqueous soluble potassium salts. The
cadmium-substituted complexes have been characterized by IR, 31P NMR, 113Cd
NMR spectroscopy and cyclic voltametry (CV). Redox activities for the
tungsten and cadmium centers have been observed by using cyclic voltammetry.
It was found that the presence of cadmium decreases the electrocatalytic
activity of the [?1-LiP2W17O61]9- and ?2-[P2W17O61]10-heteropolyanions.
Plasma Malondialdehyde Levels in Children on 12-Hour Cyclic Parenteral Nutrition: Are There Health Risks?
Authors: Dine Thierry , Gressier Bernard , Luyckx Michel , Gottrand Fréderic , Michaud Laurent , Kambia Nicolas
Published: June 2014

In children undergoing total parenteral nutrition (PN), lipids provide a key source of calories preventing or correcting energy deficits and improving outcomes. However, some of these lipids may undergo oxidation leading to the formation of malondialdehyde (MDA), a cytotoxic byproduct found in these patients. This paper aims to describe a sensitive method for detecting MDA and discuss its role in certain diseases commonly found in children on regular PN. To quantify MDA levels in children benefitting from long-term cyclic PN, a reliable and sensitive high-performance liquid chromatographic method based on a 1-step derivatization/extraction procedure analysis with ultraviolet determination at 305 nm wavelength was achieved. In control children without PN, MDA levels were on average 3.30 ± 0.08 μM. However, in children nourished intravenously by fat emulsion for a long time, in which liver problems have been identified, the circulating concentrations of MDA ranged widely at both the start and the end of a session, 3- to 10-fold, respectively, in comparison with the levels measured in controls. This finding indicates that PN administrated long term raises plasma MDA levels, indicating chronic exposure and therefore a possible health risk, particularly liver damage. This preliminary study using a limited number of patients and controls showed that children undergoing long-term PN are strongly exposed to MDA, which must be considered as a potent toxic compound rather than a simple marker of lipid peroxidation.