bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Effects of Formation Hardness, Abrasiveness, Heterogeneity and Hole Size on PDC Bit Performance
Authors: Mensa-Wilmot Graham , Fear Martyn J. 
Published: December 2007

Abstract
Improvements in drilling efficiency and economics are continuously being achieved with PDC bits, specifically in medium-hard and non-abrasive formations – normal drilling. These gains have been aided by advancements in PDC bit technology, their selection practices and BHA design.
However, PDC bit performance in harsh environments – hard, abrasive and heterogeneous formations – still lacks consistency and predictability. The problems associated with these applications are amplified when large hole sizes (diameters greater than 12") are drilled. Performance qualifiers such as footage, and especially rate of penetration (ROP), tend to be considerably lower in such instances. Considering the depths at which small hole sizes (diameters less than 9") are usually drilled, the likelihood of such hole sizes being drilled in harsh environments tends to be very high. It is evident that huge operational savings will be achieved if the performances of PDC bits are improved.
This paper will discuss the effects formation hardness, abrasiveness and heterogeneity have on PDC bit performance. In addition, it will establish the influences different hole sizes have on PDC bits, especially in harsh environments. Drilling efficiency will be discussed in terms of operational parameters, vibrational behavior, durability equivalency (DEQ) and lithology differences. An engineered approach to PDC bit development and selection, that enhances performance in harsh environments and in large hole sizes, will be discussed.
Intensive Evaluation of a Rig's Fluid Handling System Shown to Dramatically Improve Efficiency, Lower Costs
Authors: MacEachern D. P. , Hudson C. E. , Toups B. 
Published: December 2007

Abstract
A comprehensive and quantitative evaluation of the mud mixing, solids control and waste management systems on rigs prior to the commencement of a drilling operation has been shown to dramatically improve operational efficiency and ultimate fluid-related costs.
This paper discusses the evaluation process, which includes an audit of the total fluids system, aimed at assuring that the solids control, fluids handling and mixing systems are functioning to specifications and configured properly for the well objectives. The authors will examine in detail the various components of an intensive rig evaluation, which include everything from the condition and configuration of the shakers to the dimension of the mud pits and their fittingness for treating and processing the specific mud volumes required for a given project. In addition, the evaluation includes a safety audit of all areas where fluid engineers will be working, such as the pit room and shaker house.
In demonstrating the effectiveness of such an evaluation, the authors will consider specific examples, including audits conducted on newbuilds, rigs undergoing refurbishment and even to improve the solids control and waste management efficiency of units while a well was in progress. The authors will discuss the results of an evaluation of an entire fleet of deepwater rigs with emphasis on the subsequent recommendations. On one deepwater rig in the Gulf of Mexico, the operator saved $48,000 in fluid-related costs when the evaluation revealed that the solids control equipment was not operating at peak efficiencies. Many existing rigs are found to require only a minimum amount of repair or adjustments to show improvements. On most occasions, the evaluation can be used to construct more efficient solids processing and waste management plans.
Successful Horizontal Drilling and Gravel Packing in Deep and Ultra-Deepwater
Authors: Vozniak J. P. , Mathis S. P. , Hogg W. C. , Ratterman E. E. 
Published: December 2007

Abstract
This paper discusses specialized completion tools and techniques developed while drilling and completing the open hole sections of 20 horizontal gravel packs and 3 Level 5 multi-lateral wells completed in Campos Basin, offshore Brazil. The discussion covers wellpath planning, pumping operations, wellpath selection, multilterals, the use of extended-longevity well screens, floating rig operations, and fluid systems to prevent formation damage.
Open hole horizontal wells are attractive in ultra-deep water because the approach eliminates a liner and allows a larger casing string at the reservoir. This method also provides extensive reservoir exposure. Couple this technology with multi-laterals and a significant reduction in the number of wells to adequately drain the reservoir may be achieved.
Twenty open hole completions have been successfully performed in the deepwater Marlim field offshore Brazil. These include both gravel- and non-gravel-packed completions in horizontal producers and injectors. Additionally, three Level 5 multi-lateral wells with open hole completions have been successfully installed in the same field.
Multi-lateral (ML) completions have been classified as Levels 1 through 6, depending upon junction functionality. Only Levels 5 and 6 pertain to this discussion. Only Levels 5 and 6 provide pressure integrity at the junction. Level 5, a cased and cemented main bore and laterals, achieves pressure isolation at the junction with packers. Level 6 is similar to Level 5 except that pressure isolation at the junction is achieved using the casing.
A New Method Of Determining Range And Direction From A Relief Well To A Blowout Well
Authors: Morris F.J. , Waters R.L. , Roberts G.F. , Costa J.P. 
Published: December 2007

Abstract
A method utilizing four component-type magnetic sensors for the determination of range and direction from a relief well to a blowout well is presented. The advantages of using component-type magnetometers and magnetic gradient information are enumerated. The equipment and its operation are described. Typical examples of results obtained in field operations are given and their analysis is discussed.

Introduction
There are few events more frightening than a fiery catastrophic blowout on an offshore drilling platform. In an astonishingly short time the rig disintegrates and sinks onto the ocean floor, leaving only a huge gas bubble boiling through the water's surface. If the escaping gas does not continue to burn, it is generally ignited for safety. Onshore blowouts can be equally devastating, particularly if the surface conductor is not particularly if the surface conductor is not accessible. Under either of these circumstances the most successful way to bring the blowout well under control is to drill a relief well directed so as to intersect the blowout well, or to get sufficiently close to the blowout well at the problem area so that fluid communication between the two wells can be effected. Thereafter the kill attempt can be accomplished and the blowing well brought under control. See Figure 1.
As simple as this procedure may appear, the exact location of the relief well and the blowout well at depth are seldom known with sufficient accuracy to assure an effective kill operation. The principal reason for this is that well surveys are typically made with precisions no greater than a quarter of a degree. At a depth of 10,000 feet this means that each well may be anywhere within a circle of 87 feet diameter. Furthermore, additional cumulative deviations can occur in both wells which would substantially increase the areas of these circles of uncertainty. In the worst case, the two wells may be too far apart to establish communication by any reasonable means. In the critical situation of attempting to control a blowout well, the range and direction from the relief well to the blowout well must be known.
In late 1975, Houston Oil and Minerals Corporation commissioned Tensor to develop a system for making such measurements.
P. 1
Formation and Control of the Vaterite Scale Polymorph of Calcium Carbonate in the Galley Field Development
Authors: Brankling D. , Bayman M. , Jenvey N. 
Published: December 2007

Abstract
Producing wells in the North Sea Galley Field development require application of scale inhibitor at the sub-sea wellheads to prevent formation of calcium carbonate scale across the sub-sea chokes. The wells tie back to the Northern Producer Floating Process Facility (FPF) through rigid carbon steel flowlines which also require chemical inhibitor application to control corrosion. Historically a combined scale / corrosion inhibitor has been applied to provide the necessary scale and corrosion protection downstream from this point in the production process. Following a series of process upsets which occurred in 1999 due to topsides scale formation, the vaterite polymorph of calcium carbonate was identified as the primary scaling species produced in the process system, with subsequent research showing that vaterite formation was induced by the use of corrosion inhibitor in the process stream. This paper presents information on the stabilisation of the normally metastable vaterite polymorph of calcium carbonate and questions the common perception of direct scale inhibitor / corrosion inhibitor incompatibility as a primary factor in reduced inhibitor performance.
Scale Potential of a Deep Water Field - Water Characterisation and Scaling Assessment
Authors: Rosario F. F. , Bezerra M. C. M. 
Published: December 2007

Abstract
This paper presents the methodology for characterisation (sampling and analysis) of formation water and scale prediction in the waterflooding project of a deep-water field, from Campos Basin, Brazil. A subsea well A, representative from an oil-producing sandstone reservoir of this field was selected for sampling. Bottom-hole sample was taken in the open hole well at the oil-water contact using a modular formation dynamics tester – MDT. After completion operations, both wellhead and bottom-hole samples (positive displacement sampling – PDS) were collected in the aquifer zone.
The gas from the bottom-hole samples was analysed using chromatography. Bicarbonate determination was performed at offshore laboratory using a controlled microprocessing titration.
As the water sample at the oil-water contact was similar to the composition of the aquifer, it was used to predict the scaling potential in the field. Two models were considered for prediction: the thermodynamic model OKSCALE and the geochemical code GWB. These models predict the precipitated mass and calculate the saturation index (SI) of the most common scales in an oilfield during waterflood operations (BaSO4, SrSO4, CaSO4 and CaCO3). The mass and SI of the insoluble compounds were calculated for the various injection and formation water mixture ratios, occurring over the field life. Precipitation of barium sulphate and strontium sulphate was found to be likely at produced wells (downhole and flow lines) and surface facilities.
Factors Influencing Sulphide Scale Generation Associated with Waterflood Induced Reservoir Souring
Authors: Evans Robin 
Published: December 2007

Abstract
Iron sulphide scale can be deposited in production tubing, topsides facilities due to reservoir souring associated with water injection. One of the main mechanisms of reservoir souring is believed to be the reduction of sulphate in the injected water by sulphate reducing bacteria (SRB). To be active in the reservoir, the SRB need to be able to utilize fatty acids, which are present in the formation water, often in the cooled region of the reservoir in the vicinity of the water injection well. Consequently the location and the degree of mixing of the injected water with the in-situ brines in the oil zone and the water zone is a significant factor in the potential for reservoir souring and subsequent iron sulphide scale generation.
Brine mixing occurs to very different extents, depending on the reservoir geometry and on the presence or absence of an aquifer (water zone). When water injection is into the oil zone, banking of the connate water occurs ahead of the injected water, resulting in limited mixing of the two waters in the reservoir. When water injection is into the water zone (aquifer), the degree of water mixing is much greater, increasing the potential for biogenic reservir souring.
Based on the above discussion, water injection into the aquifer should result in a greater degree of reservoir souring than injection into the oil zone. For water injection into the oil zone water mixing in the reservoir is restricted and biogenic sulphate reduction may be delayed until the waters mix in the production facilities.
Soap-Oil Systems For Formation Fracturing
Authors: Hendrickson A.R. , Nesbitt L.E. , Oakes B.D. 
Published: December 2007

Abstract
One of the important characteristics of a fluid is its viscosity, since this is closely associated with its sand-carrying ability. From the standpoint of economy it is sometimes more advantageous to thicken a non-viscous petroleum fluid, than to use a more expensive, naturally viscous oil.
This paper discusses the use of certain alkali metal, oil-soluble soaps in. non-polar solvents, such as kerosene, diesel fuel, and crude oil. By in situ neutralization of long chain aliphatic organic acids, in a hydrocarbon media, a sodium-soap dispersion is obtained. Such soaps produce micelles, the aggregation of which results in low fluid loss and low sand-falling rates. Also, the fluid exhibits thixotropic properties, providing additional sand support without a corresponding increase in the true or Newtonian viscosity.
This paper describes the characteristics of the micellular aggregations, their formation and properties. The relationship between the apparent and true viscosities of such dispersions is shown. The effect of brine on these soap-oil systems is also discussed.

Introduction
Oil-dispersible alkali metal soaps have been familiar industrial compounds for several years; they have found many uses in various fields. Because of their unique colloidal nature in nonaqueous solvents, their use has been recently extended to formation fracturing for primary recovery of well fluids. This paper will discuss some of the aspects and properties of certain alkali metal oil-soluble soaps in non-polar solvents such as kerosene, diesel fuel, and crude oil.
Many improvements have been made in materials and techniques of application, since the introduction of hydraulic fracturing as a method of stimulating production from oil and gas wells. A variety of fluids have been employed to open fractures and carry propping agents, among which are gels, emulsions, and refined oils. Developments made during the last few years have included modifications of these fluids in order to overcome and eliminate certain difficulties that were encountered in field applications.
The most recent general development in fracturing fluids has been a soap-oil dispersion that combines the best features of other fracturing fluids and overcomes many of their disadvantages. The familiar phenomenon of mice the formation of soaps in aqueous solutions also occurs in nonaqueous media. This was demonstrated by Reuggerberg and other workers in this field. By in situ neutralization of long chain aliphatic organic acids in hydrocarbons, a sodium soap dispersion can be obtained that is a satisfactory fluid for fracturing.
Application: Monte Carlo Simulation in Risk Evaluation of E&P Projects
Authors: Komlosi Zsolt P. 
Published: December 2007

Abstract
The three basic types of risks for projects are market risk, country/political risk and business risk. While the former and the latter should be evaluated simultaneously, the country risk is applied with a special opportunity cost (discount rate) weighted with a country risk factor.
The basis of risk evaluation is the net present value calculated with a cash flow model showing the breakdown in discounted differences of all future costs and revenues throughout on entire project. The simulation model will be programmed to handle the main incoming data, which define the market and business risk (e.g., oil price, inflation, foreign exchange, reserves, ultimate recovery, specific costs, taxes and similar payables, etc.) as stochastic variables.
For defining the distribution functions as variables that reflect market risks, the basis will be the variance of values in the past and the expected figures planned in the company&apos;s premises. Some parameters are not independent (e.g., under identical circumstances lower unit costs are associated with larger reserves), therefore analysts can define a correlation between the specific parameters by historical data Those co-efficient will be applied by the utilised software during the simulation.
After running all the cycles a frequency function is compiled from the results and this will serve as the basis for defining data relating to cash flow (e.g., expected value, standard deviation, values relating to 5% or other cumulative frequency, etc.). The main indicator (borrowed from the field of financial risk management) is Value at Risk (VaR) which is the difference of the expected NPV and the NPV value at, generally, 5% cumulative frequency. Another important index is the Reward per Risk ratio of expected NPV and VaR.
Return on Investment in Energy Education
Authors: Tobin John C. 
Published: December 2007

Abstract
The paper discusses the very nebulous nature of measuring the ROI on energy education. However, it suggests that such returns are measurable in terms of an improved (more certain) business environment that would be realized with an informed (energy literate) public.
In K-12 alone there is very real demand for balanced educational programs in energy. Specifically, in spite of the lack of curriculum requirements to cover the topic, teachers are requesting educational material that meets national and local educational standards by demonstrating "good science", alternatives and cost/benefit analysis. Educators recognize that the energy theme is a great way to teach history, geography, economics, earth sciences and social sciences, etc.
The industry is asked if it will not meet this real demand for balanced energy education, who will? Education is the foundation that leads to a public that understands the importance of energy in its economic well being and in its quality of life. Such an informed public will then allow for a more stable and rational business environment for the industry. Is the industry willing to bypass this investment opportunity?
Characterizing Uncertainty in Oil and Gas Evaluations
Authors: Caldwell Robert H. , Heather David I. 
Published: December 2007

Abstract
The past 10 to 15 years have seen a major shift in thinking on the subject of uncertainty and its incorporation into oil and gas evaluations. Witness the struggle that has occurred in the adoption of probabilistic expressions of reserves estimates and the gradual acceptance of these methods by the industry. Despite this new-found acceptance, there is still much confusion on how such evaluations are performed (lack of consistent ground rules or calibration procedures) and particularly, how to use or interpret the results. The question then becomes, have we really made any progress in terms of improving the accuracy of our estimates?
This paper explores the sources of uncertainty in an oil and gas evaluation and attempts to characterize these sources by their definition and interrelationships in order to better understand how to handle them. As geoscientists and engineers, we tend to focus on generally simple computational procedures to calculate most of our required parameters. In other words, we fit a straight line through the scatter to develop a transform, calculate a result, and move on. Many empirical relationships are in standard use that were developed from very scattered data. Such methods have changed little as graph paper gave way to hand calculators, and now computers.
In characterizing uncertainty, we document the sources as including measurement inaccuracy, computational approximation, the effect of incomplete or missing data and dealing with naturally stochastic systems, and examine the impacts on the evaluation of uncertainty. Finally, comparisons are made with non-oilfield handling of uncertainty to compare and contrast concepts and the way we visualize the results.
Does this improve the accuracy of our evaluations? Read on, you will be surprised at the answer.
Predicting Natural Gas Production Using Artificial Neural Network
Authors: Al-Fattah S. M. , Startzman R. A. 
Published: December 2007

Abstract
The industrial and residential market for natural gas produced in the United States has become increasingly significant. Within the past ten years the wellhead value of produced natural gas has rivaled and sometimes exceeded the value of crude oil. Forecasting natural gas supply is an economically important and challenging endeavor. This paper presents a new approach to predict natural gas production for the United States using an artificial neural network.
We developed a neural network model to forecast U.S. natural gas supply to the Year 2020. Our results indicate that the U.S. will maintain its 1999 production of natural gas to 2001 after which production starts increasing. The network model indicates that natural gas production will increase during the period 2002 to 2012 on average rate of 0.5%/yr. This increase rate will more than double for the period 2013 to 2020.
The neural network was developed with an initial large pool of input parameters. The input pool included exploratory, drilling, production, and econometric data. Preprocessing the input data involved normalization and functional transformation. Dimension reduction techniques and sensitivity analysis of input variables were used to reduce redundant and unimportant input parameters, and to simplify the neural network. The remaining input parameters of the reduced neural network included data of gas exploratory wells, oil/gas exploratory wells, oil exploratory wells, gas depletion rate, proved reserves, gas wellhead prices, and growth rate of gross domestic product. The three-layer neural network was successfully trained with yearly data starting from 1950 to 1989 using the quick-propagation learning algorithm. The target output of the neural network is the production rate of natural gas. The agreement between predicted and actual production rates was excellent. A test set, not used to train the network and containing data from 1990 to 1998, was used to verify and validate the network performance for prediction. Analysis of the test results shows that the neural network approach provides an excellent match of actual gas production data. An econometric approach, called stochastic modeling or time series analysis, was used to develop forecasting models for the neural network input parameters. A comparison of forecasts between this study and other forecast is presented.
The neural network model has use as a short-term as well as a long-term predictive tool of natural gas supply. The model can also be used to examine quantitatively the effects of the various physical and economic factors on futuregas production.