bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hydraulic Fracture Diagnostics
Authors: Warpinski Norman R. 
Published: June 2014

Summary
Fracture diagnostics can provide important information on fracture geometry that can be used to improve stimulation effectiveness and reduce costs. Several cost-effective diagnostics already exist, and the technology for obtaining a full image of the fracture is progressing to the point of practical application.

Introduction
Hydraulic fracturing is an interesting technology that has evolved to a mature, complex level; is critical to the economical production of hydrocarbons; and is a significant portion of the well-development cost. Nevertheless, it is still not understood fully or, at least, is interpreted poorly. Some may argue that the physical laws governing fracturing are known and fracture models are accurate, but the emergence of "new mechanisms" every few years (e.g., scale-dependent fracture toughness, complex fracturing, dilatancy, and convection) suggests that the basic physics incorporated into models has not been as comprehensive as required to model a fracture fully.
The reasons for the uncertainty surrounding the fracturing process are quite clear. The Earth is a complex, discontinuous medium, and historically there has been limited technology for observing or inferring fracturing results. Nothing can be done about the complexity of typical reservoirs in the Earth, and one can expect that difficulties with complexity will increase as more marginal reservoirs are exploited. On the other hand, diagnostic capabilities continue to improve and technology is reaching the point where fracture diagnostics can be applied by the average producer in problem situations, in new fields, or for validation of new fracturing techniques.
Furthermore, as operators continue to work in difficult, complex lithologies, it becomes clear that stimulation problems cannot be solved without some diagnostic data from which judicious decisions can be made. Diagnostics cost money, but trial-and-error approaches often cost more money and can result in lost wells. Decisions on well spacing, field layout, sand concentrations and volumes, number of zones that can be stimulated in one treatment, optimum perforation schedule, and many other operational parameters can be made correctly if the proper diagnostic information is available in a timely manner. This article briefly reviews the status of stimulation diagnostics and provides some information on newer technology that is becoming available. Some of these techniques could provide information that will improve production or reduce costs.
Engineering Core Analysis
Authors: Unalmiser Servet , Funk James J. 
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
Core analysis has come a long way from the days when reservoir productivity was determined by blowing through a piece of cable-tool-produced core. Our tools and methods for drilling and core analysis have changed, but our interests have not. The reservoir-rock properties that determine hydrocarbon production, the variation in these properties, and how these properties affectultimate recovery are still of primary concern. Properly engineered core analysis provides a direct measurement of these reservoir-rock properties and is an essential step in formation-evaluation, reservoir, and production engineering. Fundamental core-analysis measurements are unchanged, but advances provide the ability to test at reservoir conditions and to acquire simultaneous measurements of reservoir-dependent properties. Core analysis today uses X-ray computerized tomography (CT) to determine two- and three-dimensional (2D and3D, respectively) porosity distributions, while continuing to apply Boyle's law and Archimedes' principle to determine porosity. Mercury injection is used routinely to describe pore-throat distributions, but nuclear magnetic resonance(NMR) is becoming a popular method to delineate relationships between poreradii and permeability. This review addresses some recurrent concerns of core analysis as well as some new approaches and insights that are part of the physical reservoir model determined by core analysis. Refs. 1 through 6 provide more information on the subject.

Coring and Field Operation
Reservoir studies seeking to interpret and define both geological and engineering parameters dictate the core-analysis program. Core analyses mustintegrate with field and production data and eliminate reservoir uncertainties that cannot be addressed with log, well-test, or seismic data. These requirements define the coring objectives that, in turn, control coring fluid, tools, and core handling. In most cases, these objectives cannot be obtained with core retrieved in a single well. Coring is thus an integral part of the reservoir-life-cycle process, with cored wells selected to verify or provide maximum information for the current geological, engineering, or production model of the reservoir.
State of the Art of Gas/Liquid Cylindrical-Cyclone Compact-Separator Technology
Authors: Shoham Ovadia , Kouba Gene 
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.

Summary
The petroleum industry has relied mainly on conventional, vessel-type separators to process wellhead production of oil/water/gas flow. However, economic and operational pressures continue to force the industry to seek less expensive and more efficient separation alternatives in the form of compact separators, especially for offshore applications. Compared with vessel-type separators, compact separators, such as the gas/liquid cylindrical cyclone(GLCC), are simple, low-cost, low-weight separators that require little maintenance and are easy to install and operate. However, the inability to predict GLCC performance adequately has inhibited its widespread deployment. Current R&D is aimed at creating the necessary performance-prediction tools for proper design and operation of GLCC separators. This paper presents the status of the development of the GLCC, the state of the art with respect to its simulation and design, and current successful and potential applications.

Introduction
The GLCC (Fig. 1) consists of a vertical pipe with a tangential inclined inlet and outlets for gas and liquid. The tangential flow from the inlet to the body of the GLCC creates a swirl that produces centrifugal and buoyancy forces on the fluids that are an order of magnitude higher than the force of gravity. The combination of gravitational, centrifugal, and buoyancy forces separates the gas and liquid. The liquid is pushed radially outward and downward toward the liquid exit, while the gas is driven inward and upward toward the gasoutlet. The low-cost, low-weight, compact GLCC separator offers an attractive alternative to the conventional vessel-type separator. A size comparison between the GLCC and conventional vessel-type vertical and horizontal separators has been conducted recently for a typical field application with oil and gas flow rates of 100,000 B/D and 70,000 Mscf/D, respectively, at 100 psig. For this case, the required GLCC inner diameter and height are 5 and 20 ft, respectively. These dimensions are approximately one-half of the corresponding dimensions of the required conventional vertical separator (9 x 35 ft) and about one-quarter of the dimensions of a conventional horizontal separator (19x 75 ft).
Managing Data Assets To Improve Business Performance
Authors: Lesslar P.C. , van den Berg F.G. 
Published: June 2014

SUMMARY
A project to improve integration of data and computer applications for exploration, appraisal, and field-development planning is ongoing at Sarawak Shell Bhd. An increased awareness of the importance of data as an asset has resulted in definition of a project aimed at improving the exploitation and management of this asset. This is expected to affect business through increased staff productivity and realization of new development opportunities through better subsurface interpretation and field management.

INTRODUCTION
During 1995-96, Sarawak Shell underwent an organizational review to transform itself into an asset-based organization. Integrated asset teams that encompass exploration, development, and reservoir-management activities were formed. During the review phase, subsurface- and surface-data management were identified as key areas that needed to be addressed and improved. Small teams were subsequently set up to define the scope and terms of reference for these projects. This paper describes the objectives and setup of the Subsurface Data Integration (SSDI) project.

PROJECT MANAGEMENT AND LOGISTICS
The goal of the SSDI project is to address the following main activities:data integration, project and corporate databases, applications- portfoliomanagement, data ownership, and procedures. Fig. 1 shows the data challenge, a key value driver for the initiative. The data challenge is from an in-house Shell study that suggested that technical professionals spend 60% of their time looking for data. The SSDI project team coordinates and drives the project and helps the business units implement the improvements. A companywide steering group makes key decisions with representatives from these business units and technical service groups. Fig. 2 illustrates the relationships between the project team, the steering group, and the asset teams. The activities carried out as part of the project are facilitated and supported by the project team but owned and driven by the asset teams through the steering group. This ensures that business requirements drive the tasks and priorities for the project team.
The History and Success of Liquid CO2 and CO2/N2 Fracturing System
Authors: Gupta D.V. S. , Bobier D. M. 
Published: June 2014

Abstract
Liquid CO2 system has been pumped as fracturing fluids in North America since the early 1980s and the liquid CO2/N2 system from 1994. The fluids have been used in over 1000 wells in a variety of formations and in wells of permeabilities from 0.1mD to 10 Darcies, depths in excess of 3000 meters and BHT from 10 to 100 degrees Celsius. The chemistry and physics of these fluids are very intriguing and are described. These include the thermodynamics of the fluids and the physical properties of density and viscosity of these fluids. The effect of compressibility and the transient effects on fluid leak off are discussed. The suggested process for proppant placement with these low viscosity, non-damaging fluids are described. This includes the density and turbulent effects. The design model considerations for the design of the fracturing jobs with these fluids are also summarized. Operational considerations of pumping these low temperature fluids in the field are detailed. A summary of the field use of these fluids is described.
Booking Reserves
Authors: Ross J.G. 
Published: June 2014

This paper (SPE 52015) was revised for publication from paper SPE 49178, prepared for the 1998 SPE Annual Technical Conference and Exhibition, New Orleans, 27 30 September. Original manuscript received 15 June 1998. This paper has not been peer reviewed.

Summary
Inconsistency in approaches used for booking reserves, whether for internal or external reporting requirements, represents a significant problem for the industry. Despite all the efforts made to establish a broadly acceptable set of reserve definitions and the guidelines published by various regulatory bodies, many areas exist where different interpretations are adopted. Therefore, the key requirement of any system, consistency, is not achieved. Inconsistency occurs at two fundamental levels:in the interpretation of what is meant by "reserves," particularly with respect to commerciality, andabout what volumes should be booked in specific circumstances (e.g., under production-sharing contract terms, where nonhydrocarbons are present, and where hydrocarbons are used on site for fuel).
The first problem may be addressed by an integrated resource-reporting system that ensures that reserves are seen in their correct context as discovered, commercial, recoverable, remaining resources. While the new Society of Petroleum Engineers/World Petroleum Congress (SPE/WPC) definitions provide a basis for the system, additional definitions and guidelines are required to ensure that an acceptable level of consistency is achieved. The second area of difficulty is related to the actual volumes booked. This is an issue that has not been addressed adequately to date. We propose a series of "guiding principles" as the basis for discussion and debate in the hope that it may lead to an improved understanding of the problem and, ultimately, to much greater consistency in the booking of reserves.
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Analysis of Slug and Drillstem Tests Under Water-Oil Two Phase Flow Conditions
Authors: Spinelli Vicente D. , Peres Alvaro M. M. 
Published: June 2014

Abstract
Special procedures for the analysis of Slug and DrillStem Tests when the produced fluid does not reach the surface have appeared in the literature over the last ten years. However, such analysis techniques are based on single phase theory. This paper considers the effects of water-oil two phase flow on the pressure analysis of such tests. In particular, this work verifies when the single phase analysis procedure modified by Perrine-Martin theory can be extended to Slug and DST with simultaneous water and oil production.
Two cases are considered: (1) uniform initial water saturation profile within the area investigated during test time, representing tests run in a transition zone; (2) a region of higher water saturation exists near the wellbore, which simulates the case where a significant wellbore fluid invasion into the formation have occurred during drilling or well completion.
It is shown that when saturation gradients are small, the wellbore and reservoir equations are weakly non-linear. In such cases the pressure solution for two phase flow can be correlated with the single phase analytical solution for both drawdown and buildup periods. For cases with a high water saturation region close to the well, the total mobility contrast between the invaded zone and the virgin zone can be represent by an apparent skin factor. During the flow period this apparent skin rapidly changes due to the cleaning effect in the invaded zone, thus the two phase pressure solution cannot be correlated with the constant skin-slug test analytical solution. The main conclusions of this work are: (1) single phase analysis procedures can be applied to both flow and buildup data, provided the saturation profile is nearly uniform; (2) when an invasion zone exists near the wellbore, single phase analysis procedures applied to buildup data give an excellent total mobility estimate of the virgin zone. Skin factors calculated from such buildup data represent a total skin, that is, the mechanical skin plus the apparent skin at the moment of shut-in. Calculated values from the flow period may not represent the virgin zone total mobility and the total skin factor.
New Directions in Foam and Aerated Mud Research and Development
Authors: Kuru E. , Miska S. , Pickell M. , Takach N. , Volk M. 
Published: June 2014

Abstract
A review of foam and aerated drilling fluid technology is presented. The review includes an analysis of foam and aerated fluid rheology and flow-pressure loss models. Problems associated with the applications of current models are discussed. Suggestions for possible model modifications and needs for future research are offered.
Recently, a new research initiative has been undertaken by the University of Tulsa to build an Advanced Cuttings Transport Facility (ACTF). Development and utilization of the ACTF will offer the industry an insight into the complex processes that govern fluid flow during drilling and production phases. The basic construction of the facility is in progress. The facility will eventually allow investigation of cuttings transport with incompressible and compressible drilling fluids at elevated temperature (200 °F) and elevated pressure (2000 psi). The design aspects of the ACTF and the scope of the project are discussed in the present paper.
Design, Implementation, and Assessment of a Sand Control Strategy For The Horizontal Completions of the West BraeISedgwick Joint Development
Authors: Mclninch B. E. 
Published: June 2014

Abstract
The North Sea Block 16/7a West Brae and 16/6a Sedgwick fields were discovered in 1975 and 1985 respectively. The developments languished for several years because of limited reserves, unconsolidated sands, and slightly heavy (22 deg API) oil. Advances in horizontal drilling techniques, mud systems, sand control, and subsea completion technology, revived the potential of an economic development during 1996. Infrastructure synergies and utilisation of an experienced core team of six Marathon engineers and one geologist, helped minimise development costs of this subsea tieback to the existing Brae Alpha platform.
This paper intends to record the considerations for effective and economic engineering of sand control requirements for the West Brae/Sedgwick wells. Horizontal wells were selected as the best solution to delay coning of water or gas, thereby maximising oil drainage. The goal of the production well design was simply to maximise recovery of hydrocarbons by minimising formation drawdown and sand production. To achieve this goal, emphasis was placed on proper engineering and testing of drill-in fluids and sand screens. The upper completion components were selected based on reliability and ease of installation to minimise costly rig time. Similar engineering emphasis was placed on the injection well design to ensure completion longevity and long term pressure support.
Thus far, the implemented completion strategies appear to have met the West Brae/Sedgwick sand control objectives. The designed drill-in fluid system cleaned up quickly and efficiently without the requirement for potential formation or screen damaging breakers. No evidence of sand production was found during clean-up to the rig, or during 16 months production.
Furthermore, results of a wireline conveyed production spinner log demonstrated flow contribution along the entire horizontal length of the first West Brae completion, thus increasing the likelihood of proper drainage. Four wells are currently producing to the host platform at a combined liquid rate of 40,000 bpd. Water encroachment has lagged model projections and productivity has exceeded expectations. A single injection well is providing pressure support to the Balder reservoir in both the West Brae and Sedgwick fields. Finally, total development costs for this project have been recovered within 16 months despite a depressed oil product price.
Where Have All the Profits Gone?
Authors: Brashear J.P. , Becker A.B. , Faulder D.D. 
Published: June 2014

This paper (73141) was revised for publication from paper SPE 63056, first presented at the 2000 SPE Annual Technical Conference and Exhibition held in Dallas, Texas, 1–4 October 2000.

Summary
Despite massive improvements in productivity due to technology advances, the E&P industry has averaged a disappointing 7% return on net assets over the last decade (less than its cost of capital). Its market capitalization relative to the S&P 500, even at recent high oil and gas prices, is about half what it was a decade ago. A small-scale, very simple case study suggests that at least part of the reason for this disappointing perform-ance lies in the way that the industry conventionally allocates capital and selects portfolios of projects. Ranking of projects by deterministic estimates of value and even some of the so-called advanced methods significantly overstates value, understates risk, and misallocates capital by incurring unnecessary, uncompensated risks. Suggestions for improvements in the project selection/capital allocation prices are offered.
Why Change?
Petroleum exploration and production is enjoying a "golden age" in technology. Over the past two decades, finding costs have fallen more than threefold and lifting costs by half or better (EIA, 1998). Three-dimensional seismic has improved exploration success rates by as much as 90% and development success rates by 30% (Bohi, 1997). Yet, at the same time, the return on net assets by the largest U.S.-based companies in the E&P sector has averaged 7% for both integrated majors and large independents. (Original analysis based on Simpson et al., 1999). This return is the result of projects selected because they all exceeded the minimum estimated internal rate of return "hurdle rates," generally set at 15% or more, and were all financed with capital that generally costs in the range of 9-12% or more. This would appear to indicate long-term destruction of shareholder value. The recent period of high oil and gas prices has ameliorated these results but not enough to offset the long-term trend.
Investors have noted these discouraging results and have responded accordingly. Relative to the Standard & Poor's 500 Index (the largest 500 U.S.-traded, nonfinancial companies), the Amex Oil Index (the 16 largest U.S.-traded oil companies) has fallen 50% between January 1990 and October 2000. This reflects real value loss relative to alternative directly comparable investments.
The Missing Ingredient in Knowledge Management
Authors: Holland Winford , Nash Bill 
Published: June 2014

Summary
A major oilfield services company commissioned research to find out what know-how was vital to the advancement of their packer business. Would it be the scientific attributes of the tools themselves, the rubber seals, hydraulics, or pressure capabilities?
Research, using a knowledge management-targeting technique, determined it was none of the above, but instead was knowledge of metal-to-metal sealing. Armed with this fact, the company proceeded to develop a competitive edge in the marketplace by finding, connecting, and energizing the critical people inside and outside the company who were "in the know" on that vital subject.
In other words, in this extraordinary technological era, knowledge management (KM) for this company was not about millisecond communication of information, but about the age-old power of what people know, the front-end of the word "knowledge." By systematically developing, integrating, and deploying what key people know, KM can be a positive force in increasing a company's value in the marketplace.
Today's KM can be traced to important work started in the 1960's and 1970's in the field then called scientific and technical information (STI). STI brought out the critical importance of enabled information flows among knowledgeable scientists and engineers for optimal technical productivity. Furthermore, STI research found that in most organizations, only a minority of the technical professions was really in the know, serving as the organizational nodes for their organization's vital knowledge.