bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Focus: Multilateral/Extended Reach (May 2009)
Authors: Negrao Alvaro 
Published: February 2015

Technology Focus
Our industry has overcome many difficulties during recent years. Successes have been achieved with drilling projects in sensitive environments, remote-access areas, and high-technological-demand projects. New technologies have been developed at a fast pace to fill the needs.
Technologies that achieve better recovery with a simultaneous reduction in capital expenditure are preferred. The use of extended-reach and multilateral wells aligned with good drilling performance will reduce capital expenditures. Although the profiles of those wells become more complex, with long horizontal sections or multiple legs, better performance is possible through deployment of an integrated project team that appropriately addresses the drilling and completion challenges during the planning phase. Subjects such as wellbore stability, well cleanliness, multilateral junctions, appropriate sand control, openhole completions, inflow-control completions, and inflow-performance relationship must be analyzed carefully during the well-design phase.
The project-team assessment during the execution phase must include the latest techniques in seismic interpretation, deployment of real-time logging tools to deal with reservoir heterogeneity, and real-time update of the Earth model. Real-time data are essential for management of equivalent circulating density because of the narrow margin between pore pressure and fracture gradient.
The well-planning process must be complemented by an improvement in operational performance. New approaches with good quality control must be implemented urgently to reduce the nonproductive time (NPT) while drilling wells. Our industry faces performance problems with wells reaching an NPT index of more than 40% in the Gulf of Mexico. The responsibility for such a high NPT index can be shared equally by drilling contractors, service companies, and opera-tors. Today, NPT in offshore wells can reach an annual cost of approximately USD 70−90 million per rig, and this will be reduced only with improvement in maintenance, better engineering practice, and qualified personnel. Integrating the drilling engineers into the project team early, use of the latest technology, and focusing on operational excellence are essential for the industry success.
Multilateral/Extended Reach additional reading available at the SPE eLibrary: www.spe.org
SPE 115099 • "Technical, Economic, and Risk Analysis for a Multilateral Well" by D. Arcos, Texas A&M University, et al.
SPE 119506 • "How Continuous Improvement Led to the Longest Horizontal Well in the World" by Kumud Sonowal, Maersk Oil Qatar, et al.
SPE 116138 • "Multilaterals Drilling and Sustainable Openhole Production From Theory to Field Case Studies" by Son K. Hoang, University of Oklahoma, et al.
SPE 115742 • "Advanced Wells: How To Make a Choice Between Passive and Active Inflow-Control Completions" by V.M. Birchenko, Heriot Watt University, et al.
Casing Ultradeep, Ultralong Salt Sections in Deep Water
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 114273, "Casing Ultradeep, Ultralong Salt Sections in Deep Water: A Case Study for Failure Diagnosis and Risk Mitigation in Record-Depth Well," by Jincai Zhang, SPE, Shell Oil Company; William Standifird, SPE, Knowledge Systems; and Chris Lenamond, SPE, Nexen Petroleum U.S.A., originally prepared for the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21-24 September. The paper has not been peer reviewed.
The deepest well drilled to date in the Gulf of Mexico (GOM), the Well 1 discovery well in Green Canyon, required setting casing in a 15,000-ft-thick section of tectonically active salt. After casing collapsed in the initial wellbore, a comprehensive model was developed to characterize wellbore stability, the salt-creep mechanism and its implications for well design, and mitigation options for future well construction.

Introduction
Subsalt and near-salt formations are among the most attractive exploration prospects in many operating areas including the GOM, offshore West Africa, Brazil, the southern North Sea, Egypt, and the Middle East. One of the characteristic features of the northern GOM salt trend is that the salt bodies are highly mobile. High mobility has two significant implications for wells drilled through salt:
"creeping" salt masses can exert catastrophic stresses on casing, and
in areas near the salt/rock interface, salt movement can create unstable rubble zones that can make drilling difficult or impossible.
One of the key challenges for well construction in subsalt environments is maintaining casing integrity. Salt-induced casing collapse has occurred in a number of GOM wells, including Well 1. Well 1 was drilled in 2005 and, at the time of construction, was the deepest well in the GOM. The well was drilled through a salt body more than 15,000 ft thick and eventually reached a total depth of more than 28,000 ft true vertical depth. The casing collapsed near the base of the salt nearly 3 months after the salt section was cased. The wellbore was abandoned and was sidetracked successfully to reach 34,189 ft.
The objective of this study was to characterize the salt-creep mechanism and its implications for casing failure in Well 1 and to develop options for well design to avoid future failure events. Well 1 experienced drilling-fluid losses and hole ballooning in the subsalt formations. Given the extreme depths, fluid losses and hole ballooning could jeopardize the feasibility of future projects in the area.
Analysis of the geomechanical environment reveals many challenges; northern-GOM salt bodies are among the most varied and complex in the world. Some are active; some are passive. On a local geologic scale, the dynamics of salt creep are dependent on such factors as temperature, salt mineralogy, and overburden.
Trapped-Annular-Pressure Mitigation: Spacer Fluid That Shrinks - Update
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 112872, "Trapped Annular Pressure Mitigation: A Spacer Fluid That Shrinks - Update," by B. Bloys, SPE, M. Gonzalez, SPE, J. Lofton, R. Carpenter, SPE, S. Azar, SPE, D. Williams, J. McKenzie, SPE, and J. Capo, SPE, Chevron; R. Hermes, Los Alamos National Laboratory; R. Bland, SPE, R. Foley, SPE, and F. Harvey, SPE, Baker Hughes; J. Daniel, F. Billings, and I. Robinson, Lucite International; and M. Allison, Flow Process Technologies, originally prepared for the 2008 SPE Drilling Conference, Orlando, Florida, 4-6 March. The paper has not been peer reviewed.
In subsea-completed wells, fluids commonly are trapped in casing annuli above the top of cement and below the wellhead. When these trapped fluids are heated by the passage of warm produced fluids, thermal expansion can create very high pressures and cause the collapse of casing and tubing strings. A successful field trial has been conducted in a 9,800-ft-deep gas well of a water-based spacer fluid that upon heat-triggered polymerization shrinks 20%, mitigating trapped annular pressure (TAP).

Introduction
TAP, also called annular-pressure buildup, is caused by the thermal expansion of fluids trapped in casing annuli between the top of cement and the wellhead. The pressure buildup usually is a result of heat transfer from produced fluids or from hot drilling fluids circulated while drilling a high-pressure/high-temperature well The pressure can exceed the collapse strength of the casing and production tubing. In land wells, the pressure is relieved easily by bleeding off some fluid through a casinghead valve. In subsea-completed wells, wellheads are much less accessible and generally not fitted with the necessary valves.
Perhaps the most successful mitigation approach has been the use of vacuum-insulated tubing (VIT). This technique generally has been successful in keeping the annular-fluid temperatures within an acceptable range. However, with the advent of deeper and hotter wells in deep water, the limits of the protection provided by VIT are being approached in two ways. First, deeper wells have much higher hanging weights that are reaching the stress limits of VIT designs. Second, the greater depths also are producing higher temperatures. Even with the insulating effects of VIT, the temperatures are sufficiently high that pressures are predicted to increase to unacceptable levels.
A new approach created a water-based spacer fluid to be used just ahead of the cement. The spacer contains 10 to 30% emulsified liquid methyl methacrylate (MMA) monomer. The liquid MMA shrinks 20 vol% upon polymerizing. The polymerization is triggered by heat and an appropriate chemical initiator. MMA is emulsified into a simple water-based fluid that is intended to be the last spacer pumped just ahead of cement, filling most of the open annulus. The monomer has a low flash point similar to methanol, and it must be handled carefully but has a long record of safe industrial use.
Technology's Value in the Upstream Oil and Gas Industry
Authors: Daneshy Ali , Bates Tom 
Published: February 2015

The petroleum industry has long grappled with the assessment of the value of technology and its role in corporate strategies. Over the past 2 decades, the questions posed by who pays for, who owns, and who benefits from technology have created an increasingly fractured view of new product development. This has created a paradoxical environment in which E&P technology funding is declining at a time when the incentive for developing new technology has never been greater.
The value of E&P technology is well documented. In the 1990s, three significant new technologies changed the landscape of the industry. Multiple streamers deployed in the acquisition of 3D seismic dramatically reduced the cost of high-quality data. The creation of multiclient libraries made it possible for smaller independent operators to play in the same league with supermajors in geographic domains such as the Gulf of Mexico. Horizontal drilling, including logging-while-drilling and geosteering tools, made it possible to drill “designer” wells in complicated offshore environments and substantially increase the rate of recovery in ordinary reservoirs. Finally, subsea and deepwater technologies allowed the industry to access reserves in unprecedented water depths. Coupled with seismic and drilling advances, deepwater offshore fields were placed in production at costs lower than anyone could have imagined a decade earlier. One supermajor reported that real finding and development costs and operating expenses per barrel dropped by more than 50% from 1985 to 1995. It is not surprising then to note that annual worldwide oil discoveries nearly doubled from the early 1990s to the late 1990s as these new technologies became fully deployed.
This perspective provides an insight into the enormous value that technology can create for the oil and gas industry. Even a small incremental reduction in the cost of each barrel of produced oil generates enormous savings when one considers that globally the industry produces in excess of 100 million BOE/D. Unfortunately, the oil price collapse of 1998–99 destroyed much of this technology momentum. New technologies have not replaced the value created by 3D seismic, horizontal drilling, and deepwater products. As a result, discoveries are lower (Fig. 1) and costs are higher today than 10 years ago.
Owner Reaps the Benefits
In many other industries, such as computers, pharmaceuticals, and electronics, technology is directly responsible for generation of value. The developers, owners, and financial beneficiaries are the same. However, because the E&P industry is very different from consumer-focused industries, a dramatically different picture emerges. With the majority of potential value creation in the reservoir, the owner of the reservoir typically gains much larger benefits than the owner of the technology. As long as technology is available and accessible, the owner of the reservoir can reap its benefits with-out having to directly participate in its development. This is the conundrum that we seek to resolve.
Cost-Effective Methane Emissions Reductions for Small and Midsize Natural Gas Producers
Authors: Fernandez Roger , Petrusak Robin , Robinson Donald , Zavadil Duane 
Published: February 2015

Introduction
U.S. demand for natural gas continues to grow dramatically, in large part because methane is the cleanest-burning fossil fuel. Onshore and offshore drilling and production continue to expand, often in very challenging plays ranging from shallow low-pressure coalbed methane to deep high-pressure/high-temperature gas production. A significant amount of this demand is expected to be met by independent producers.
The U.S. Dept. of Energy estimates that small and midsize independent operators produce more than two-thirds of the natural gas in the lower 48 states. Independent producers drill 85% of new gas wells in the U.S., and 80% of these companies have fewer than 20 employees. Methane emissions from the U.S. natural gas production sector are approximately 150 Bcf/yr. With record sales prices for natural gas and high consumer demand, natural gas producers have great incentive and opportunity to reduce currently lost product and increase their revenue. Often many small producers lack the time and technical staff to research and evaluate cost-effective methane emission reduction opportunities, yet there are numerous proven and cost-effective methane emissions reduction technologies and techniques that are available today to the small to midsize producer.
While individual releases of methane may appear to be minor, emissions are often continuous in nature, and cumulatively they become economically significant. This article provides information on methane emission reduction options that were developed by operators and promoted by the U.S. Natural Gas STAR Program, and are economic for small and midsize producers. In addition to increased revenue through reduced methane loss, many of the technologies and practices outlined here reduce operating costs, increase overall production, and provide high rates of return. All of these technologies and practices have been reported by gas producers through their participation in the Natural Gas STAR Program. This paper provides information and tools to help independent producers determine the most profitable gas emissions savings options for their operations.
We describe 25 cost-effective methane emission reduction technologies and practices in Table 1, provide costs and savings data in Table 2, and crosswalk technologies and practices with production characteristics in Table 3 to help determine where each methane savings option is most likely to work. Finally, we provide a method to scale this data to your operation and calculate your potential economics in Fig. 1.
High-Stakes National and International Litigation: Management Issues
Authors: Welsh Ron , O'Gorman Kevin 
Published: February 2015

An employee has just sued an oil and gas company for U.S. $1 billion on behalf of himself and countless unnamed people who have nearly identical claims. What does company management do?
From equipment accidents to plant and pipeline explosions to gas releases and chemical spills, oil and gas executives regularly face risks that would terrify executives in other fields. The resulting lawsuits often mushroom into myriad class-action law-suits with plaintiffs clamoring for enormous damage recoveries. At the same time, “lesser” lawsuits in all shapes and forms abound, including litigation ranging from sexual harassment to royalty claims.
Because of the oil industry’s sweeping size, scope, and complexity, the industry is not just fertile ground for legal action—it is a veritable petri dish. In the post-Sarbanes-Oxley world, more and more oil companies have come to believe that legal matters are just as much management business as legal business. The more that management knows about the broad issues of lawsuits, the more prepared it will be to know how to direct its lawyers and guide its case to a successful conclusion.
Class-Action Lawsuits
Because class-action lawsuits are potentially the most costly of all litigation that oil companies may face, it is helpful to know the basics. First, class-action suits can make cases involving large numbers of people more manageable for both sides: plaintiffs and defendants. For example, when scores of people claim to have suffered similar harms, it is impractical to bring each of these claims to trial individually. If a court agrees, a class-action lawsuit may proceed in the name of one or only a few individuals representing all similar claimants. Ultimately, all the unnamed claimants are governed by the issues determined to be common to the group.
At the outset of class actions, management and its attorneys should make a pivotal decision—Does the company embrace the idea of a class action or not? Surprisingly, the answer is not always “no.” Occasionally, management may tolerate, if not welcome, a class action for sound management reasons. For instance, when any large business such as an oil company has a potential exposure, it should objectively analyze that exposure in terms of the size of the claim, the strength of its defense, and the cost to defend or settle later. As an example, one lawsuit for U.S. $1,500 scarcely qualifies as a significant exposure to any large company. But 10,000 carbon copies of that lawsuit can make just the attorneys’ time to manage and defend each one ruinous. Consider the number of formerly vibrant companies that ended up in bankruptcy as a result of thousands of asbestos claims.
That is why, as odd as it sounds, the chant “Turn it into a class action” may occasionally be the company’s mantra as much as it is the claimant’s. As a result, the question is usually better asked as, “Forget the claimants; does a class action give the company a way to put a widespread exposure behind us at a wholesale cost rather than at 10,000 retail costs?”
Overview: Deepwater Exploration and Production (June 2005)
Authors: Barnes John E. 
Published: February 2015

In recent years, the industry has met some amazing deepwater technology challenges. Drilling and production in water depths that just a few years ago would have seemed impossible now are considered routine. Not long ago, a site in water depths greater than 150 m was considered deep, and the Cognac Project—at more than 300 m—was considered a remarkable feat of technology.
Today, the feasibility of a project in 2000-m water depth is not an issue. Instead, project efforts focus on topics such as design robustness, effective project-execution strategies, reliability of operations, and cost-effectiveness. It is a tribute to technical innovation that, for most deepwater projects in less than 2000 m of water, several different acceptable methods often are available to solve specific technical challenges.
Operators, designers, constructors, and installers continue to improve deepwater technologies and reduce cost and schedule risks. Areas such as well testing, reservoir evaluation with minimal data, riser systems, and flow assurance are being addressed to improve project execution and delivery. Meanwhile, new projects are benefiting from the application of lessons learned from previous efforts.
Recent work has achieved promising results in special projects for which water depths reach 3000 m. Today’s challenge is to make the issues at that depth as commonplace as those in less that 2000 m. From a historical perspective, it is truly startling that work on these challenges is proceeding in an almost routine manner, with complete confidence that viable solutions will be found.
Additional Deepwater Exploration and Production Technical Papers
Available at the SPE eLibrary: www.spe.org
SPE 92616 Mooring and Riser Management in Ultradeep Water and Beyond
SPE 91012 Incorporating Uncertainties in Well-Count Optimization With Experimental Design for the Deepwater Agbami Field
Available at the OTC Library: www.otcnet.org
OTC 17292 Holstein Truss Spar and Top Tensioned Riser System: Design Challenges and Innovations
OTC 17683 Lessons Learned From the Evolution and Development of Multiple-Line Hybrid Riser Towers for Deepwater Production Applications
Barracuda and Caratinga Development Project
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 17052, "Barracuda and Caratinga Development Project," by L.G.S. Messias dos Santos, Petrobras, originally prepared for the 2005 Offshore Technology Conference, Houston, 2-5 May. Copyright 2005 Offshore Technology Conference. Reproduced by permission.
The Petrobras Barracuda and Caratinga project is a deepwater oil-production development in the Campos basin, offshore Brazil. The fields are in water depths of 600 to 1350 m and have reserves of approximately 1.75×105 m3 of oil and 12.5×109 m3 of gas. The project is being developed through a major turnkey engineering, procurement, and construction (EPC) contract. The EPC contract consists of converting two tankers into floating production, storage, and offloading (FPSO) units (the P-43 and P-48) capable of processing 2.385×104 m3/d of oil each; drilling and completing 54 wells; and developing the associated subsea system. This paper is an overview of the project.
Introduction
The Barracuda and Caratinga project was developed in two stages: a pilot system, followed by installation of the definitive system. The pilot system evaluated oil-production potential and gathered data characteristics of the reservoir and fluid properties. Operations began in September 1997 by exploring both fields through the P-34 FPSO. Eleven production wells from Barracuda and Caratinga fields were tied back to the FPSO, which had a liquid-processing capacity of 7.15×103 m3/d. This pilot system was demobilized in October 2002. The definitive system comprised the conversion of two very large crude carriers into two FPSOs: P-43 and P-48. In this stage, 54 wells were connected to these platforms through a subsea system. The development of the Barracuda and Caratinga definitive systems was combined into one unique project, and a single design was used to procure and build the twin FPSOs.
Field Background
As Fig. 1 shows, the Barracuda and Caratinga fields are 160 km east from Macaé (182 km northeast of Rio de Janeiro). The Barracuda field was discovered in April 1989, and the reservoir covers an area of 233 km2 with water depths ranging from 600 to 1100 m. The Caratinga field was discovered in February 1994, and the reservoir covers an area of 260 km2, with water depths ranging from 850 to 1350 m.
The proven reserves are 1.675×105 m3 of oil equivalent, and the total reserves are 1.8125×105 m3 of oil equivalent, according to SPE criteria. The average specific gravity of the produced oil from these fields is 0.91 g/cm3.
The pilot system provided oil-production estimates, gathered information to define the draining plan, and, hence, reduced the technical risks in the final conception. The pilot system also provided supplementary knowledge regarding the reservoirs, confirming information obtained from 3D-seismic and the exploratory wells. Use of the information and new technology reduced the number of wells needed from the predicted 129 vertical wells to 54 horizontal and multilateral wells.