bluuebunny/crossref_metadata_2025_split huggingface dataset:
Big and Clean - A Novel Design for LNG Plants
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper IPTC 11637, "Big and Clean - A Novel Design for LNG Plants," by Barend Johan Jan Pek, Kaart Sander, and Elion Wiveka, Shell, prepared for the 2007 International Petroleum Technology Conference, Dubai, 4-6 December. The paper has not been peer reviewed.
The demand for clean and afford-able energy translates into a large demand for liquefied-natural-gas (LNG) production capacity. To meet this increase in production capacity, increasingly larger processing-train sizes have become the trend. A mega-train design is presented for production of more than 10 Mt/a. Much of the LNG expansion is taking place in the Middle East. A typical feed-gas composition from this region was selected as the basis for integration of gas conditioning (treating), natural-gas-liquid (NGL) extraction, liquefaction process, and utility facilities.

Introduction
The demand for natural gas is forecast to grow by 3%/yr over the next 15 years, with demand for LNG growing by 8–10%/yr. For several years, many projects have been under way, resulting in a constrained contractor market, a worldwide heavy demand for raw materials, and issues regarding logistics of work force and products. These challenges lead to large trains, particularly where large resources are involved, as in the Middle East, Russia, and Australia.
An increasingly important challenge is the need to minimize CO2-emission rates. High efficiency is a crucial enabler. Higher efficiency increases the amount of LNG that can be produced for the selected power turbines and compressors that make up a large part of the capital costs. Therefore, the focus is extended to the use of exhaust heat.
The full-length paper presents a train design for LNG production at a rate of 11 Mt/a. The design is based on Shell's Parallel Mixed Refrigerant (PMR) Process, which uses propane refrigerant in the precool cycle. Depending on project-specific conditions, such as climate and market opportunities, other designs may be more suitable. The double-mixed-refrigerant process was selected for the Sakhalin LNG project currently under construction (Fig. 1).
The PMR concept is scalable from 11 to 6 Mt/a by changing helper-motor size or changing to smaller gas turbines. Improved fuel efficiency by use of waste-heat recovery is applicable to several designs, thus minimizing CO2 emissions.

Design Premises
Plantwide integration of heat generation and demand is provided by steam. The full use of waste heat from the gas-turbine exhausts enables a step change in plant efficiency with respect to conventional LNG-plant designs and can help to reduce the specific CO2 emissions.
This design uses air cooling. Dedicated attention to hot-air recirculation and plot-plan optimization provides a robust design. Should cooling water be available for a once-through or recirculating cooling system, this can be incorporated and will further improve fuel efficiency and, depending on cooling-water-supply complexity, also the specific cost.
Conversations: Engagement Provides Its Own Rewards
Authors: Fattahi Behrooz 
Published: February 2015

President's column
My travels as the President-Elect, and now as the 2010 SPE President, have taken me to many countries. These trips have reminded me of how and why SPE evolved from being an entity incorporated in Texas to a truly global organization.
I think it is useful for members to understand how our business structure (Fig. 1) helps us to serve our global membership. At one time, the Society's demographics were such that our membership was easily served by a Dallas-based business. As our demographics changed, we saw the need to open offices outside the U.S. Opening offices in London and Kuala Lumpur in the 1990's were big steps in improving services to members outside North America. The addition of an SPE office in the Middle East in 2003 provided additional support in that growing region. Even with these offices, we still faced challenges of timely provision of services, along with currency-exchange issues and diverse business practices in countries where SPE members reside, which prompted consideration of a new business structure.
In 2004, SPE established its business structure as a Stichting, a not-for-profit society registered in The Netherlands, which has many similarities to U.S. foundations, including tax-exempt status. The SPE Stichting is the parent organization to a number of subsidiaries, which are subject to the laws of the countries where they operate.
Although we have a complex business structure, its workings are transparent to members. You are only aware that we are able to provide services to you worldwide in an efficient manner, wherever you are located!
SPE has about 250 staff located in our offices around the world to help in the delivery of our services to nearly 90,000 members in 116 countries. You can see why we rely on you, our members, to help us conduct our business. Volunteers are SPE's point people who are the enablers of our services and deliverers of our products. Without their passionate engagement and dedicated time and effort, SPE will not be successful in what it intends to accomplish.
About 5,000 volunteers work on the 170 section boards, 200 student chapter boards, 100+ meetings and conference committees, and 19 standing committees, as well as on the 27-member SPE Board of Directors.
With the expertise and time of volunteers, we are able to carry out our mission of technical knowledge exchange.
Reality Checks for Well Time and Cost Forecasts
Authors: McIntosh John 
Published: February 2015

Management
Much has been written to explain the origins of the credit crisis that has engulfed the international financial system. At the heart of each explanation is the failure to quantify commercial risks. The companies at the centre of the crisis were often long-established, considered profitable, and were endowed with great resources to make mathematical models of their activities. Despite this, it is safe to conclude that many of their models were wrong. Risk is a feature of financial transactions and drilling wells that no amount of engineering will completely remove. From the crisis in banking it is obvious that the skills required to build a credible model of activities inclusive of risk are in short supply.
It would be convenient to assume that because the energy industry employs lots of numerate people it is good at quantifying uncertainty; unfortunately, many of the time and cost models used for well planning can be easily disproven. The reasons for this go beyond the tools available to the human bias toward optimism. There is a tendency to treat each well project as unique and disregard the fact that past performances will not only inform us about averages but also about uncertainty.

A Suitable Benchmark
The budget for new well projects will often first be defined with little detailed engineering information. There are perfectly valid reasons for this; out of a basket of many prospects an operator is unlikely to develop every one. Early budgetary estimates play a part in the selection of the best prospects to drill. Irrespective of the method used to define a budget figure, and irrespective of the maturity of the estimate, some guidance on confidence should accompany the result. In common with any other forecasting discipline, well cost estimation never is and never will be an exact science. The very best that can be done is to describe the probability of a particular scenario and to use the results from similar previous wells to back this up.
If a model of well project duration cannot be substantiated with empirical evidence it must be treated with extreme caution. The inputs to the model matter much less in this respect than the output; it is surprisingly easy to make a poor probabilistic model from good information. In many mature drilling provinces such as the UK, public data can be used to provide the justification necessary for models of project duration which in turn can be used to model cost.
Technology Focus: Drilling and Completion Fluids (November 2009)
Authors: Estes Brent 
Published: February 2015

Technology Focus
The success or failure of a well is a function of many factors. One important influence is the drilling fluid. As companies deal with drilling more-complex and -difficult wells, a well-designed drilling fluid can contribute to the success of the well. The year's highlights range from laboratory studies on fluid/chemical effects that relate to borehole stability to complex-fluid physical properties that mitigate lost returns.
With ever-increasingly complex wells being drilled, the role of a drilling-fluid engineer has changed as well. When I started in the fluids industry 15 years ago, we were concerned mostly about controlling fluid loss, plastic viscosity, yield point, and gels. To meet today's challenging wells, we have to be educated about the aforementioned fundamental properties as well as borehole stability, narrow-margin drilling, and lost returns, in addition to environmental regulations and waste management.
A good example is in the lost-returns arena. With the increasing understanding of rock mechanics, a more systematic approach to lost-returns remediation was developed. Only a few years ago, most people were unfamiliar with concepts such as "building stress or integrity" and terms such as "hoop stress," "stress cage," and "fracture-closure stress." No longer are the days of pumping "everything but the kitchen sink" down the hole in an often futile attempt to stop losses! Now, we take a science-based approach to fluids and engineer the particle sizes to stop lost returns and reach drilling objectives in less time and at a lower cost.
The roles of fluids specialists working for operators and fluids companies are changing as well. They have become knowledgeable about more than just fluid makeup and properties. Companies have engineers and scientists on staff who research issues such as borehole stability, lost returns, waste management, and environmental regulations around the world.
Please take time to read the following summaries as well as the suggested additional reading.
Drilling and Completion Fluids additional reading available at OnePetro: www.onepetro.org
SPE 120646 • "Quest for a Pragmatic Drilling-Fluid-Performance Index—Key to Improving Fluid Performance and Optimizing Quality-Well-Delivery Economics" by Peter Osode, SPE, Petroleum Development Oman, et al.
SPE 123013 • "Changing Shale Strengths With Invert-Emulsion Drilling Fluids: Theory, Measurement, and Modeling" by T. Hemphill, Halliburton, et al.
SPE 119269 • "Drilling-Fluid Design Prevents Lost Returns by Building Integrity Continuously While Drilling in East Texas" by Kenneth B. Vaczi, SPE, ExxonMobil, et al.
First Deepwater Well Successfully Drilled in Colombia With a High-Performance Water-Based Fluid
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 120768, "First Deepwater Well Successfully Drilled in Colombia With a High-Performance Water-Based Fluid," by J. Marin, SPE, F. Shah, SPE, M. Serrano, SPE, A. Jaramillo, and C. Marin, Halliburton, and W. Arevalo and G. Priandi, Petrobras, originally prepared for the 2009 SPE Latin American and Caribbean Petroleum Engineering Conference, Cartagena, Colombia, 31 May-3 June. The paper has not been peer reviewed.
Deepwater drilling presents significant issues and uncertainties, especially when there is no prior drilling experience in the area. Uncertainties about the drilling conditions create additional risk to operators and can cause project budget overruns. Innovative technologies often are implemented to help ensure that the well is drilled efficiently and safely. Drilling-fluid selection was a key decision to the success of the project.

Introduction
Deepwater exploration activity in the oil and gas industry continues to present new hurdles requiring innovative technical solutions. These difficult wells can increase the risk factor and result in potentially higher operational costs. In most cases, an oil-based drilling fluid is selected as the first option because of the high daily costs associated with a deepwater operation and the advantages gained in wellbore stability and rate of penetration (ROP) compared to conventional water-based systems. However, tightening environmental regulations and high costs associated with cuttings and oily fluid disposal are sufficient reasons to seek viable water-based fluid alternatives that could provide an oil-based-drilling-fluid performance.
Water-based drilling fluids that simulate the performance of oil-based drilling fluids, commonly are referred to as high-performance water-based fluids (HPWBFs). The main benefits of these systems are reduced environmental footprint and lower costs associated with cuttings and fluids disposal.
Petrobras Colombia undertook the challenge of drilling the first deep-water well in Colombia in 1,840-ft water depth in the Tayrona Block in the Caribbean Sea north of Colombia. Because of environmental restrictions, uncertainties about formations that would be encountered, and the need to protect the target zone from damage, an HPWBF was selected to drill the well.

HPWBF System
Fluid selection presented several challenges related to drilling the exploratory well. The operator rejected the option of using an oil-based fluid because of environmental restrictions and cuttings and fluids-disposal complications. The HPWBF used met the required criteria and was designed for maximum shale inhibition in highly reactive formations and provided wellbore stability, high ROPs, and acceptable rheological properties over a wide range of temperatures. It had been run successfully in the Gulf of Mexico in shelf and deepwater operations.
Stage-Gate Project-Management Process in the Oil and Gas Industry
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 102926, "The Good, the Bad, and the Ugly of the Stage-Gate Project-Management Process in the Oil and Gas Industry," by G.W. Walkup Jr., SPE, SDG, and J.R. Ligon, SPE, Consultant, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.
Management teams speculate on major capital projects to drive company performance. Capital committed to megaprojects has increased at a compounded average growth rate of more than 12% during the last decade, and this trend is expected to continue over the next decade. To manage the shareholder value that is at risk in these projects, most companies have invested heavily in a formal stage-gate project-management process (PMP). Yet the performance of major projects has not improved appreciably, and significant project failures—both technical and economic—continue to occur. Key organizational and technical shortcomings that diminish project performance are identified, and actions that management can take to gain significant competitive advantage are suggested.

Introduction
Spending in excess of U.S. $2 billion over a 5-year period for a single project is accepted. Most companies have adopted a stage-gate PMP to manage these projects. While differences exist, there is much similarity among the different PMPs. For this paper, the process and nomenclature shown in Fig. 1 are used. The focus is on the first three phases of the PMP because they are most relevant to petroleum engineers.

PMP Overview
A PMP should create greater shareholder value from major projects while simultaneously protecting people and the environment. Fig. 2 is a model of how shareholder value is created, beginning with value identification and ending with value delivery. The role of a PMP in this value-creation cycle is to improve value identification through improved decision quality and to improve value delivery through improved project execution.
The five-phase stage-gate process in Fig. 1 is the PMP that has evolved from companies' beliefs about shareholder-value creation and management's ability to influence it. Three of the five PMP phases are focused on value identification, and frequently they are referred to collectively as front-end loading (FEL). Each phase has a specific goal and ends with a decision to move the project to the next phase, redo the current or prior phase, or drop the project altogether. The exception is that the final phase, Operations, has no terminal stage-gate decision.
Faster and Longer Bit Runs With New-Generation PDC Cutter
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 102067, "Faster, Longer, and More-Reliable Bit Runs With New-Generation PDC Cutter," by J. Clegg, SPE, ReedHycalog, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.
A new process for manufacturing polycrystalline-diamond compact (PDC) cutters creates a wrapped thermostable region across the face and around the periphery of the PDC cutter. This differs significantly from existing first-generation thermostable product because the treated region has complex geometry in three dimensions. The full-length paper describes the new cutter geometry and shows how the thermostable region supports the cutter as it slowly wears.

Introduction
Historically, there has been a trade-off between abrasion and impact resistance of PDC cutters. Typically, impact resistance was achievable by use of a larger diamond grain size but at the expense of abrasion resistance. The first attempts to extend the envelope of PDC-bit and -cutter performance occurred in the mid-1990s when multimodal polycrystalline diamond was introduced. This used a mixture of grit sizes from 50 to 2 µm in diameter, allowing the smaller grits to fill the voids left between the larger particles, resulting in a much denser polycrystalline-diamond layer that improved abrasion resistance.
Additional improvement was achieved by use of nonplanar interfaces. The move from planar to nonplanar interfaces was driven by a desire to reduce stresses at the interface between the polycrystalline diamond and its tungsten carbide substrate.
The introduction of the nonplanar interface combined with the multimodal polycrystalline-diamond mix provided significant improvement in both relative toughness and relative wear life over planar multimodal materials. The thicker diamond edge that resulted improved relative abrasion life.

Thermostable PDC Cutters
Cobalt normally is present in the creation of polycrystalline diamond in the PDC press. It is introduced in the tungsten carbide support, where it acts as a cement. At the elevated temperature and pressure where diamond-to-diamond bonding occurs, the cobalt migrates into the diamond grit and helps to catalyze the bonding process. It also forms a bond with the tungsten carbide substrate and ensures that the PDC is one integral component. However, cobalt significantly reduces the thermal stability of the PDC because it has a greater coefficient of thermal expansion than the surrounding diamond particles. Between 700 and 760°C, the cobalt expands and forces the diamond-to-diamond bonds apart. This results in the rapid breakdown of the compact. What appears to be abrasive wear when a dull PDC bit is analyzed often can be the result of the breakdown of the diamond-to-diamond bonds because of overheating. Therefore, it is important that the temperature of the PDC cutter is maintained below 700°C to avoid thermal breakdown. Unfortunately, the cutting-tip temperature often exceeds this critical limit.
Step Change in Performance: Upgraded Bit Technology Improves Drilling Economics
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 103074, "Step Change in Performance: Upgraded Bit Technology Significantly Improves Drilling Economics in GOM Motor Applications," by B. Grimes, SPE, and B. Kirkpatrick, Hughes Christensen, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.
Operators in the Gulf of Mexico (GOM) are constantly looking for ways to reduce the costs of drilling development wells. A new steel-tooth (ST) roller-cone bit with an advanced metal-seal bearing has achieved this goal and is having a significant effect on drilling economics. Improvements in bearing life, seal reliability, and cutting-structure durability have resulted in more time on bottom, giving the operator the confidence to use the new roller-cone bits in long directional hole sections.

Introduction
With large regions of the GOM rapidly becoming mature provinces, operators are looking for ways to reduce the costs of drilling development wells. Most of the wells drilled are directional, and heavy water-based drilling fluids often are required in the intermediate hole sections. Relatively high bottomhole temperatures combine with high bottomhole pressures and balling shales to present a challenging drilling environment. Operators strive to increase rate of penetration (ROP), maximize hours on bottom for each bit, reduce risk, and complete the section with fewer bits to reduce the number of trips.
Improved roller-cone bits with an innovative single-energizer metal-seal (SEMS) bearing were introduced in 1998 (Fig. 1). A step change in bit life was realized, yet it took a year or two for operators in the GOM to gain sufficient confidence in the new ST bits to run them harder and leave them in the hole longer. By 2000, operators routinely were achieving runs as much as twice as long as was typical with the predecessor elastomer-sealed ST bits, particularly at higher rotary speeds (e.g., 175 to 275 rev/min). In 2000, enhanced ST cutting structures were introduced to complement the SEMS bearing (Fig. 2). The new ST cutting structure provided longer tooth life by improved tooth wear resistance and reduced tooth breakage.

GOM Drilling Environment
The GOM drilling environment is one of the most diverse in the world. With exploration and development programs taking wells to ever greater depths, the demands placed on ST roller-cone bits and their sealed-bearing systems become increasingly severe. The increased service life and reliability of rotary-steerable systems and top-of-the-line motor assemblies allow them to successfully drill long, complex well paths, which increases the directional challenges for roller-cone bits. Both concentric and eccentric hole-opening technologies place unique loading conditions on roller-cone bits when they are used as pilot bits.