bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hard or Soft Shut-In: Which Is the Best Approach?
Authors: Jardine S. I. , Johnson A. B. , White D. B. , Stibbs William 
Published: December 2007

ABSTRACT
A concern relating to operational procedures following detection of a kick is whether closure of the blow-out preventer (BOP) with the choke valve shut, termed a "hard" shut-in, is likely to cause formation damage due to generation of a pressure pulse in the well-bore fluid. This has prompted some operators to opt for a "soft" shut-in whereby the choke valve is left open at closure of the BOP. The delay in closing the choke to obtain complete shut-in of the well, however, results in additional influx from the formation.
This paper describes a series of tests which have been conducted using a full-scale drilling rig and test well equipped with complete surface instrumentation and including downhole pressure measurements to resolve the hard or soft shut-in question. In this way quantitative downhole pressure measurements in a realistic well-bore environment were obtained for comparison with theoretical predictions made from analysis of the pressure wave propagation in the well.
Test results and theoretical analysis are presented to describe the issues relating to choice of shut-in procedure. Agreement between experiment and theory shows that the formation experiences negligible additional pressure when using a hard shut-in procedure and that the additional influx and well-bore pressures associated with the soft shut-in are avoided.
Reducing the Cost of Top-Drive Drilling System Installation: A Case History
Authors: Hock C. J. 
Published: December 2007

ABSTRACT
Ways to reduce the installed cost of a top drive drilling system on a jack up rig are presented. The cost and time saving aspects used on the Offshore Mercury, i.e., not increasing the height of the derrick through the use of a power swivel drilling system and an electronic crown protection system are highlighted, as are the modifications to the DC-DC drilling power to enable it to emulate the control features of an SCR powers system. The major aspects of the installation are touched upon and the actual schedules followed and manning level used during the systems installation are presented as are the relative cost savings.
Lubricity and Wear of Shale: Effects of Drilling Fluids and Mechanical Parameters
Authors: Dzialowski Andrew , Hale Arthur , Mahajan Satish 
Published: December 2007

Abstract
The predominant limitation to directional and extended-reach drilling is excessive torque and drag. Although torque and drag data exist for sandstone and metal surfaces, over 70% of the formations drilled worldwide are classified as shales. Unfortunately, data on shales are limited because of practical restrictions.
Clearly, shales behave differently than metal and sandstone because of their chemical and physical properties. Chemical interaction between shale and the drilling fluid can change the mechanical properties of shale and significantly affect shale lubricity and wear characteristics.
The primary objective of this paper is to present for the first time a systematic study of the effects of various salts and other common water-based mud additives on the lubricity and mechanical wear of shale. Also provided are data on diesel-based inverts and synthetic-based drilling fluids. Tests were run on Pierre shale as well as Berea sandstone for comparison. The study was made possible by the recent development of a laboratory device specially designed to accommodate shale test blocks under heavy loads.
The Development of Improved Soft Formation Milled Tooth Bits
Authors: Liang D. B. , Keshavan M. K. , McDonough S. D. 
Published: December 2007

Abstract
The introduction of FDS+ bits in 1991 has significantly improved the performance of these types of soft formation milled tooth rock bits. Average bit life has been increased significantly, resulting in a substantial reduction in drilling cost. Tooth grading of the FDS+ bits also is much better than that of conventional milled tooth bits. In certain locations, the new FDS+ bits have approached the life of some soft formation tungsten carbide insert (TCI) rock bits.
This paper documents the successful development and application of these improved milled tooth bits, and briefly describes the following:
Design innovation of the newly-patented radiused crest tooth. Development of improved hardfacing materials and process. Field-test results.
An Interpretative Log Analysis Computer System
Authors: Breitenbach E.A. , Thurnau D.H. , Dougherty E.L. 
Published: December 2007

Abstract
This paper describes a computer software system recently developed for use of well logs in regional exploration and mapping. The system enables a log analyst to develop two-dimensional areal contour maps of requested exploration criteria from a file of digitized well log data.
The backbone of the system is an efficient computer procedure for recognizing and "compiling" the computations specified by the analyst. The desired computational processes are supplied as part of the input data in the form of algebraic or logical statements. The software system compiles the statements on data cards, translating them to psuedo-machine code. An efficient interpreter then is able to execute the analyst's statements. If an algorithm proves to be useful repetitively, means are available to include it within the permanent system. Thus a log analyst can use the permanent system. Thus a log analyst can use the system as a convenient laboratory to develop improved exploration techniques. Input from the analyst into the system could be of batch type or through time-sharing terminals. Output includes line printer tables, plots and contour maps.
The software system is described in detail and examples of its use are given.
Introduction
Several papers have appeared in the literature during the past five years describing computer software systems for quantitative evaluation of well logs. The first systems to be developed were those that computed values for variables such as water saturation, porosity and shaliness for a single set of data from one zone. The data was manually selected from the analog print normally obtained at the well site. The second generation of systems were those that operated on a larger set of data—in general the digitized data from all traces throughout a large portion of the well were used.
Onsite Disposal of Rig-Generated Waste Via Slurrification and Annular Injection
Authors: Louviere R. J. , Reddoch J. A. 
Published: December 2007

ABSTRACT
The technique of using on-site injection of oil base cuttings into a casing annulus is widely accepted as an environmentally attractive, cost-effective disposal alternative. A joint research project was undertaken by Conoco with a cuttings injection service company, Apollo Services, to pursue technological enhancements to the original technique. The result of the research initiative was development of a means to incorporate other non-hazardous wastes into the cuttings slurry. The slurrification and the disposal by injection of a wide variety of waste products is now potentially possible. The cuttings/waste injection process, nicknamed "CUTWIP", provides both a systematic design assessment for implementation and a mechanical means of accomplishing this task. Process utilization eliminates repeated handling and transport of waste products from the drilling rig to land disposal sites. The risk of accidentally discharging either solid or liquid waste into the Gulf of Mexico waters or any other environmentally sensitive area can now be minimized.
This paper addresses development of the CUTWIP process, equipment and operational requirements, well design, permitting, and project economics. Results of the initial field application undertaken while drilling the East Cameron 56 JB-3 well in the Gulf of Mexico are also reviewed.
High-Pressure, High-Temperature Drilling: Data Management and Interpretation
Authors: Buchan Robert 
Published: December 2007

Abstract
The acquisition and management of drilling data is of critical importance for high pressure, high temperature wells if well objectives are to be achieved and well control incidents avoided. Key decisions such as when to set casing or when to raise mud weight are often crucial. This paper presents a summary of BP Exploration's most recent high pressure, high temperature drilling experiences and concludes that the Success of any high pressure, high temperature drilling operation depends on pre-planning, training, communication and data management.
A Clarified Xanthan Drill-In Fluid for Prudhoe Bay Horizontal Wells
Authors: Beck F. E. , Powell J. W. , Zamora M. 
Published: December 2007

Abstract
A clarified xanthan drilling fluid was designed in order to replace the arctic diesel based drilling fluid conventionally used to drill horizontal wells in Prudhoe Bay. Use of this fluid in conjunction with well design changes has resulted in reduced drilling costs and increased well productivity. The fluid is designed to exhibit a true yield stress, which in conjunction with pipe rotation improves hole cleaning in high angle holes. The fluid is also non-damaging, provides shale inhibition, and is environmentally safe.
Recommended Practices for Heat Management of Steamflood Projects
Authors: Ziegler V. M. , Crookston R. B. , Sanford S. J. , Merrell J. M. 
Published: December 2007

Summary
Recommended practices are given for the steamflood heat management process: data collection, data analysis and adjustments to steam injection. A generic monitoring data table is presented which can be tailored to an individual project. The various options for modeling steamfloods are contrasted. A set of metrics is proposed which allows monitoring progress toward optimal operation. Project teams are endorsed as a way of ensuring that the diverse disciplines required for effective heat management are properly focused. A case example is presented that illustrates the proposed methodology.
The Meaning of Reserves in Context of Global Economic Security and Survival
Authors: Bogart A. J. , Ebneyousef M. H. 
Published: December 2007

ABSTRACT
The estimation of reserves is not based on a universally accepted standard method involving science and technology. In addition, the terms reserves, resources, deposits, and accumulations are often used interchangeably.
The reserves depend on the recovery efficiency and the availability of sustainable production capacity. The estimation of reserves also involves geological and engineering judgment affected by bias by companies and governments alike. Moreover, commercial reserves – the "real" reserves – will be produced with a reasonable degree of certitude, but technical reserves – the "paper" reserves – will not.
In the context of global economic security and survival, we are only interested in "real" reserves, not in the "paper" reserves claimed by companies and governments.
In the post-Cold War era, new industry standards need to be adopted worldwide and implemented by multilateral institutions upon which their assistance is contingent.
The Potential Role of Future Environmental Regulations on the Domestic Petroleum Industry
Authors: Godec M. L. , Kosowski Bundhrig , Haverkamp D. S. , Hochheiser Bill 
Published: December 2007

ABSTRACT
Increased environmental compliance requirements could have a significant impact on future U.S. oil and gas supplies. This paper summarizes the results of a recently published National Petroleum Council (NPC) assessment of constraints on future North American natural gas production and use1, along with a concurrent study of future oil supplies by the U.S. Department of Energy (DOE). The paper identifies possible environmental and legislative initiatives affecting domestic exploration and production (E&P) operations, characterizes the potential impacts of these initiatives on future compliance costs, and estimates their potential impacts on future oil and gas supplies.
The assessment was performed for two potential future environmental regulatory scenarios: a "balanced" scenario, and a more stringent regulatory scenario. Each environmental compliance scenario was assessed under two "reference case" economic scenarios. The estimated impacts of potential increased environmental compliance requirements are presented in terms of the following: (1) unit compliance costs; (2) economically recoverable resources (reserves) and future production potential lost; and (3) incremental industry expenditures.
The results of this assessment show that increased environmental compliance requirements could have a significant impact on the U.S. oil and gas industry and future U.S. oil and gas supplies. Depending on the level of future economic growth, the industry could incur an additional $70 to $86 billion in increased environmental compliance expenditures over the 1992 to 2010 time period. Under a high (stringent) regulatory scenario, a substantial portion of otherwise economic oil and gas resources could become uneconomic to develop and produce. Stringent environmental compliance requirements could result in 26% higher initial costs for new gas wells, and 32% higher costs for new oil wells. Annual operating costs could increase by 59% for gas wells and 43% for oil wells. Crude oil production in the U.S. could decrease by 290,000 to 620,000 B/D by 2010 under a high regulatory scenario, depending on the level of future economic growth. Under this stringent environmental regulatory scenario, U.S. gas production could decrease 2.0 to 2.3 Tcf/year.
Site Assessment Methods in Determination of Liability in Oil and Gas Property Acquisition and Divestiture
Authors: Wilson M. J. , Kiser S. C. 
Published: December 2007

ABSTRACT
This paper will identify oil and gas property due diligence auditing procedures for quantification of environmental liabilities and assets for both acquisitions and divestitures.
There are many site assessment guidance manuals and auditing programs, brief as well as very detailed, available to direct the general business of liability determination in site assessment. These guidance manuals and auditing software provide an excellent regulatory checklist to organize a site assessment but are lacking in guidance on how best to focus a site assessment on oil and gas producing properties. The most effective site assessment and audits are performed by professionals who know both how the oil business operates in the specific area and what the relevant environmental regulations are.
Efforts in a site assessment for acquisition and divestiture of oil and gas operations can be focussed by: Preparing an inventory of permits necessary for operation, reviewing their compliance conditions, and field verification of compliance.Reviewing all operations where non-hazardous and hazardous chemicals are used and hazardous waste streams are generated with the idea of identifying physical non-compliance rather than documentation violations.
A comprehensive review of regulatory compliance is still necessary but major areas of liability and assets can be identified early in the site assessment process. Many environmental problems which are identified on a property would not be classified as a "deal killer". But, quantification of identified problems in terms of the cost to remedy the problem can significantly reduce the value of the property. Environmental assets can significantly add to the value of the property. In addition, environmental permitting can impact the scheduling of new projects. Delays in project scheduling will in turn affect the property's fair market value.
Slaying the Capital Budget Constraint
Authors: Schuyler J. R. 
Published: December 2007

ABSTRACT
There is an unresolved, fundamental issue in capital budgeting. Companies that plan against a capital constraint are usually rejecting some projects which appear profitable. This discussion reasons that a capital constraint is inconsistent with knowing a company's Marginal Cost of Capital (MCoC). The incongruity arises because MCoC represents that additional funds are available at this rate, even if the full budget has been committed already. Thus, an extra project that would provide a return greater than MCoC should be funded, because it would contribute net value to stockholders. Companies accepting this reasoning can greatly simplify their project decisions. In particular, the widespread practice of ranking projects under an arbitrary capital budget ceiling is unnecessary.
The most fundamental and least assailable corporate decision policy is: Choose the alternative providing the greatest contribution to stockholder value. Although theoretically sub-optimal, there may be situations that preclude this decision policy in favor of project ranking. Also discussed are issues with valuing projects from a stockholder perspective and with implementing a value-driven decision policy.
An Integrated Approach To Characterize Low-Permeability Reservoir Connectivity for Optimal Waterflood Infill Drilling
Authors: Malik Z. A. , Silva B. A. , Brimhall R. M. , Wu C. H. 
Published: December 2007

Abstract
This study defines and investigates the Hydraulic Interwell Connectivity (HIC) concept to characterize and estimate the reservoir connectivity. This approach is an integrated study of reservoir characterization, geostatistics, production performance and reservoir engineering. In this study HIC is quantitatively defined as the ratio of observed fluid flow rate to a maximum possible (ideal) flow rate between any combination of any two wells in the producing unit. The spatial distribution of HIC was determined for the net pay of a reservoir by geostatistics. It was used as a guide for selecting infill well locations to optimize waterflood infill drilling. A low permeability carbonate reservoir producing unit, J.L. Johnson "AB" was used to illustrate the application of HIC. In simulation study, three production wells 27, 107 and 109 were realigned according to HIC distribution which resulted in an additional 10% (10,000 STB) of waterflood oil recovery.
Case History of Reservoir Simulation and Resulting Development of an Enhanced Oil Recovery Project, Henry Enhanced Recovery Unit, Unita County, Wyoming
Authors: Warren J. B. , Mullarkey J. C. , Grass V. J. , Breit V. S. 
Published: December 2007

Abstract
A detailed geological and compositional simulation study of the 4A Dakota Sand in the Henry Field, Uinta County, Wyoming was authorized by the Henry Field Technical Committee in April, 1991. The 4A Sand is a retrograde gas condensate reservoir. In April 1991, ownership of the reservoir involved three separate sets of working interests; the Henry Unit Participating Area (PA), South Henry Unit PA, and the Marathon Federal #16-1 well. The Henry Unit PA initiated an ongoing pilot injection program in December, 1985. The study was undertaken to determine the economic feasibility of further developing the 4A Sand in the Field by expanding the pilot injection to increase recovery of liquids in the 4A Sand.
Following a geological study of the structure, thickness and continuity of the 4A Dakota Sand in the Field, a compositional simulation model was used to obtain a match to the Field's 3 years of primary and 6 years of cycling history. This model was then used to study alternate producing schemes, ranging from continuation of historical practices to expansion of the dry gas cycling project by the addition of three injectors, to accelerated expansion of the project by adding injectors and producers and hydraulically fracturing all new wells and the lowest productivity existing wells.
The compositional model predicts that 16% of the original 13,880,000 barrels of condensate in place in the 4A Dakota Sand would have been recovered if gas injection had never been initiated. The FULL EXPANSION CASE predicts recoveries as high as 64.6% of the maximum possible oil recovery.
Prior to initiation of the accelerated expansion project, a Henry Field Enhanced Recovery Unit (HERU) was formed from existing working interest tracts based on participation parameters approved by the Technical Committee and approved by the Working Interest Owners. At the end of 1992, injection well drilling, compression installation, and gas plant construction were in progress at the HERU with an expanded project start up date of early 1993.
Perforation Friction Pressure of Fracturing Fluid Slurries
Authors: Willingham J. D. , Tan H. C. , Norman L. R. 
Published: December 2007

ABSTRACTEven though pressure drop across perforations for clean fracturing fluids can generally be accurately predicted, it is not well understood for fracturing slurries. In this paper, two wellbore models-one transparent and one high pressure-were used to study the perforation friction pressure behavior of sand laden fluids. The transparent model constructed with cast acrylic allowed visual observation of fluid exchange in the "rat-hole" and flow patterns of the slurries in the wellbore and through the perforations. Critical velocity at which sand begins to screenout at the perforations was also determined. Tests were performed in the high pressure model varying gel concentration, sand concentration, proppant size, and perforation diameter to gather pressure drop data. The effect of the ratio of perforation diameter to the average proppant size on the sand screenout tendency at the perforation was also investigated.A correlation to predict the change of perforation coefficient due to proppant erosion was developed from the laboratory data. This paper presents a field procedure to better estimate the change of perforation coefficient during proppant stages for calculating the change of perforation friction.Incorporating this change of perforation pressure drop during proppant stages in the real-time bottomhole treating pressure calculation will enhance interpretation of the treatment analysis.
Reservoir and Stimulation Evaluation of the Berea Sandstone Formation in Pike County, Kentucky
Authors: Frantz J. H. , Hopkins C. W. , Lancaster D. E. , Jochen J. E. 
Published: December 2007

ABSTRACT
The Gas Research Institute (GRI) has been sponsoring a three-well cooperative program with Ashland Exploration, Inc. (ΑΕΙ) during the past two years evaluating the Devonian Shale and Berea sandstone formations in Pike County of eastern Kentucky. The COOP 2 was targeted to evaluate the Berea and was GRI's first comprehensive tight gas sand research project in the Appalachian Basin. The objective of the research was to use and apply technologies developed previously in other GRI research. This paper will summarize the integrated reservoir and hydraulic fracture descriptions determined from analyzing the data collected in this project. The results presented can be applied by operators to better understand the productive mechanisms in the Berea reservoir, to predict well performance, and to design completion procedures and stimulation treatments. The methodology can also be applied to other tight gas sand formations.