bluuebunny/crossref_metadata_2025 huggingface dataset:
Overview: Reserves/Asset Management (December 2007)
Authors: Rietz Dean
Published: February 2015

What does it mean to manage reserves and assets in the context of the oil- and gas-production business? It really means making the right decisions under significant, yet potentially calculable, uncertainty. Whether you are a small independent or a large state-owned oil company, you face many of the same problems—only the scale or magnitude is different. In our industry, we face more than our fair share of uncertainties in managing assets. Those "unknowns" are pervasive throughout the many aspects of oil and gas exploration. A few of the more significant ones are as follows:Geological (structure)Petrophysical (rock properties)Drilling successEffectiveness of completionsDrive mechanism (recovery efficiency)Political (country risk)Contractual complexities and reversionsTiming of first oil for new developmentsImpact of weatherProduct price

This set of uncertainties obviously comprises a nonexhaustive list of the many factors that should enter into the review and planning processes. In spite of the unknowns that complicate our work, we still need to make decisions—decisions that are made to maximize true asset and/or shareholder value. As engineers, we can help to make those decisions the correct ones by providing decision makers with as much relevant information as possible, along with the appropriate risks and uncertainties associated with that information. Many times, we make less-than-optimal decisions because of a lack of desired information. However, we continuously strive to make the best decisions possible on the basis of the data at hand. The papers highlighted in this segment should help illustrate some ways that others are reducing uncertainty to help make their decisions the correct ones. In addition, some of the referenced papers help provide guidance and consistency in the reserves-estimation process. Ultimately, that type of consistency will reduce the uncertainties of asset valuation and improve asset management.

Reserves/Asset Management additional reading available at the SPE eLibrary: www.spe.org

SPE 107709 "Beyond Portfolio Optimization" by L.C. Faya, Constellation Energy Commodities Group, et al.

SPE 109012 "Reservoir-Management Aspects of the Rejuvenation of the Forties Field, UKCS" by Owen Vaughan, SPE, Apache Corporation, et al.

SPE 110617 "Methods for Incorporating Costs, Pricing, Gas Shrinkage and Transport Tariffs, NGL and Inert Revenues, and Working Interest in Gas Plants and LNG Projects Into Reserves Estimates" by John McLaughlin, SPE, Ryder Scott Company, et al.
Reserves and Resources Classification, Definitions, and Guidelines: Defining the Standard!
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 107693, "The 2007 SPE/AAPG/WPC/SPEE Reserves and Resources Classification, Definitions, and Guidelines: Defining the Standard!," by John R. Etherington, SPE, PRA International, and John E. Ritter, SPE, Occidental Petroleum, prepared for the 2007 SPE Hydrocarbon Economics and Evaluation Symposium, Dallas, 1–3 April.

In late 2004, a focused effort was begun to update the 1997 SPE/World Petroleum Council (WPC) Petroleum Reserves Definitions and the 2000 SPE/WPC/American Association of Petroleum Geologists (AAPG) Petroleum Resources Classification and Definitions. Evolution of the industry, driven by advancements in technology, the international expansion of the E&P sector, and the increasing role of unconventional resources in meeting global energy needs, drove the update. The 2007 system builds on previous industry efforts to provide sufficient guidance to achieve a high level of consistency in estimating resource quantities; it incorporates best practices identified in other international petroleum and minerals classification systems. Assessments may be conducted using deterministic and/or probabilistic methods. To satisfy requirements of the full range of industry stakeholders, the 2007 system introduces additional classification and categorization terminology. The resulting document is a set of technical guidelines that can be adopted by oil and gas companies to manage their business better. Moreover, it forms a standard that can be referenced by government agencies in defining reporting requirements.

Introduction

All assessments of in-place and recoverable petroleum quantities, their forecast delivery profile, and associated costs and revenues have significant inherent uncertainty. However, it is essential for future planning that governments, lenders, investors, and producers have access to consistent and reliable assessments, and that results be presented in a common format to communicate these underlying risks and uncertainties. The task of creating and maintaining the framework and language to support such communication has been assumed primarily by a consortium of professional societies: SPE, WPC, AAPG, and the Society of Petroleum Evaluation Engineers (SPEE). Their work is coordinated through the SPE Oil and Gas Reserves Committee (OGRC).

The OGRC was charged to recommend revisions and clarifications to maintain a standard for petroleum evaluations. The 2007 petroleum reserves and resources classification, definitions, and guidelines has been titled the Petroleum Resource Management System (RMS) (SPE 2007) and is hereinafter referred to as SPE-RMS or simply the SPE system; this label is intended to recognize the valuable contributions of the cosponsoring organizations (WPC, AAPG, SPEE), without whose input the resulting product would not have been generated.
Technology Integration in the Caspian
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 106858, "Technology Integration in the Caspian," by Ian Pannett and David Hodgson, BP plc, prepared for the 2007 SPE Digital Energy Conference and Exhibition, Houston, 11–12 April.

BP's Azerbaijan Strategic Performance Unit (ASPU) was developed to meet key challenges of operating within the Caspian region and to maximize business value. Key challenges include complex depletion plans; unconsolidated reservoirs; a difficult-to-drill overburden; and an integrated development, gathering, and export system. To meet these challenges, advanced seismic, intelligent completions, zonal-flow monitoring and control, and field of the future (FOF) technologies collectively address the business challenges.

Introduction

Integration is key for the Azerbaijan strategy, specifically the technology strategy. The assets and reservoirs are integrated in a variety of ways and designed to operate in an integrated way. This integration is essential to maximize reservoir recovery. As the strategy developed, increased integration could create additional opportunities for performance improvements.

Azerbaijan Assets

As shown in Fig. 1, the BP-operated assets center on development of two very large hydrocarbon reservoirs in the Caspian [the Azeri, Chirag, and Guneshli (ACG) oil fields and the Shah Deniz (SD) gas development], although it is fully expected that other assets will be added. In addition, BP operates two major pipelines through which these hydrocarbons are exported—the Baku-Tbilisi-Ceyhan (BTC) and the South Caucasus Pipeline (SCP), which originate at the Sangachal terminal, south of Baku. These pipelines are designed to take ACG and SD reserves to market with capacity to take oil and gas from other fields and operators. A fully redundant data network is in place linking all facilities with a high-bandwidth optical-fiber "ring-main" backed up by satellite data systems. Fig. 2 summarizes the ACG full-field development.

Technology Plan

The 5-year technology plan integrates all functional and asset-based activities across business areas supporting the ASPU. The strategy includes leadership in a few key areas, efficient deployment of technology in other areas, bias toward rapid application of proven technology, and healthy progression of options in selecting available technologies. This strategy has helped to focus and prioritize technologies.

The technology plan was developed in conjunction with field-depletion plans. The technology plan also was designed to improve ultimate recovery. The current ACG-development plans recover approximately two-thirds of the potential. Obtaining maximum value requires sophisticated reservoir management and application of advanced technologies such as multilateral completions and other enhanced-oil-recovery technologies.
Subsea-Data Management
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 18744, "Subsea-Data Management," by Brian Drakeley, SPE, Weatherford International, Svein Omdal, SPE, Statoil, and Sigurd Moe, SPE, FMC Technologies, prepared for the 2007 Offshore Technology Conference, Houston, 30 April–3 May.

This project will contribute toward making real-time reservoir-monitoring and other downhole data avail-able every where on Statoil's network infrastructure. The goal is to resolve hurdles for implementing fiber-optic monitoring and data transmission from subsea developments. Focus is on detailed seabed-system solutions to create an open high-speed communication infrastructure, which fiber-optic technology enables. The project will develop interfaces with existing subsea systems that have only electrical low-bandwidth communication systems.

Introduction

In June 2005, Statoil requested technical and commercial proposals relating to the development of integrated fiber-optic systems (an integrated subsea communications system) and reliable downhole sensors.

There are two key project areas:Downhole-sensor (DHS) sand monitoring (identification and quantification), multiphase flowmeter (for intelligent-well applications), and distributed pressure and temperature measurementsIntegrated fiber-optic subsea system (IFOSS) containing subsea well-sensor interrogation solutions, a subsea-control system, a subsea telecommunication and transmission system, and an integrated fiber-optic system

Fig. 1 illustrates the scope of the project and how these key project areas fit into the total integrated system.

DHS Real-Time Reservoir Monitoring

Essentially, in-well monitoring systems are required that deliver high-quality measurements throughout the life of the well without the need for routine maintenance or intervention. With no downhole electronics in existing fiber-optic systems, sensing systems are intrinsically more reliable than electronics-based systems.

With increased demand for more data on reservoir and well performance, communication systems must have that significantly improved signal performance, data density, and trans-mission distance, which leads to a fiber-optic solution.

Existing Downhole Fiber-Optic Sensors

Currently, there are four types of optical sensing systems.

Pressure/Temperature (P/T). Many P/T fiber-optic gauges have been installed and are very reliable.

Distributed Temperature Sensing (DTS). DTS systems are the most widely used fiber-optic sensing system. These systems provide a continuous temperature log of the well along the entire length of the fiber [e.g., a production (or injection) thermal profile of the well] and can be used to identify well problems; water, gas, and steam breakthrough; gas lift valve and system performance monitoring; and paraffin and hydrate formation monitoring. Measurement points are at 1-m intervals, and temperature resolution can be on the order of ±0.1°C.
Comments: Rig Boom
Authors: Donnelly John
Published: February 2015

Editor's column

Despite the current global financial crisis and recent steep decline in commodity prices, the market outlook for drilling rigs remains strong. Demand for deepwater units, in particular, remains healthy. Even with a global recession, world energy demand is projected to rise in the medium term and companies are moving to deeper waters and frontier areas to secure new production.

Mobile offshore drilling rig demand in almost all of the world's major drilling centers have been posting 90%-plus utilization rates, and strong demand and tight rig supply have contributed to strong dayrates. A rig that may have brought in USD 200,000/day a few years ago can now earn USD 500,000/day and recent contracts for deepwater rigs have topped USD 600,000/day. A surge of interest in new drillships, semisubmersibles, and high-end jackups has occurred the past several years and some of those are now entering the market. The best markets for floating rigs have been Brazil, west Africa, the US Gulf of Mexico, and southeast Asia.

In addition, 181 rigs are currently being built or on order, including 85 jackups, 54 semisubmersibles, and 42 drillships, according to Citigroup energy analysts. Of these 181, more than half are currently under contract. While about 69% of the floaters (drillships and semisubmersibles) have contract commitments, only about a third of the newbuild jackups do, so it is unclear how many will become operational.

Some of that newbuild interest is turning toward rigs that can operate in particularly harsh conditions, such as the Arctic, or in ultradeepwater. Rigs in the Barents Sea—where Gazprom, StatoilHydro, and Total are developing the world-class Shtokman gas field—will need to withstand unprecedented harsh climatic conditions and vast icebergs. Shtokman will require three of the largest platforms in the world, ice-resistant and capable of withstanding 25 m waves. Three seabed pipelines will carry the gas to shore to terminals in Teriberka in the Murmansk region, where an LNG plant will be located.

Buoyed by recent discoveries and ambitious development plans, Brazil has emerged as the dominant leader in the drilling rig market. Utilization rates there are at 100% with 31 semisubmersibles and nine drillships in the region under contract. State oil company Petrobras is reportedly in the market for as many as 40 deepwater rigs, even though it has already contracted the majority of the existing ultradeepwater fleet. That indicates that there is still a shortage of deepwater rigs worldwide, even if the global economy and oil demand soften. West Africa rig utilization is nearly as strong, at 97%. And China's offshore deepwater oil and gas development has also set off rig construction activity.

The global credit crunch is limiting the ability of companies to get financing and may slow the pace of newbuilds significantly, however. Higher steel and equipment prices combined with the tighter finance market already appear to have cooled off the speculative newbuild market.
The Coming Shootout at the LT Corral
Authors: Lovie Peter
Published: February 2015

Guest editorial

The traditional pipeline infrastructure in the US Gulf of Mexico (GOM), perhaps the most efficient in the world, faces new challenges as fields lie further and further from shore, in deeper and deeper water, and increasingly in mountainous seabed terrain. The apparently obvious tanker solution is not so easy in US waters with the Jones Act requirement to use higher-cost US-built and -manned tankers, often at economics and availabilities different from international trade. Only last year were the contracts signed for the first shuttle tankers in the GOM, for operations starting in 2010 at the early production system (EPS) being used for the Cascade/Chinook development (Petrobras operated with Devon and Total as partners).

The stakes are high, with transportation contracts in the billions of dollars, whether for pipeline or shuttle tankers. A "shootout" threatens to become immediate, with the export mode to be decided in the next year for longer-term, full-field developments: Jack/St. Malo (Chevron operated) and Kaskida (BP operated). I work for Devon, which has large minority interests in both of these developments plus many other Lower Tertiary (LT) prospects—some Devon operated (such as Bass, now drilling) and some not. Each time our company runs the numbers, we see how the economic prize on the export negotiating table is huge and how the traditional pipeline solution is challenged like never before.

These two different transport modes have battled it out in the GOM intermittently since 2001. So far, the pipeliners have prevailed over the tankermen.

The laws of physics and economics will soon be tested in the marketplace as pipeliners and tanker companies square off on transporting crude oil production from the remote locations of LT prospects in the GOM. What is different this time is the combination of distances, water depths, and the scale of investments. When it stretches the technical and economic limits of the pipeliners, the tanker people just steam a little further out. And if the field plays out early, the tankermen just go somewhere else with their vessels.

During 2000 and into mid-2001, deepwater export was the theme of a low profile but intense competition for exporting production from BP's coming developments. It went down to the wire: bids and counter bids, pipe vs. storage vessel, and tanker export. The regulatory picture was not clear back then—US government approval of the Minerals Management Service (MMS) Environmental Impact Study approving floating production, storage, and offloading (FPSO) vessels and shuttle tankers in the GOM was not given until December 2001. And use of tankers would have prevented a steady income from partial or complete oil company ownership of a pipeline. The prize went to the pipeliners in what is now the Mardi Gras system. Pipeliners 1, Tankermen 0.
Techbits: Nigeria Annual Conference Draws International Crowd
Authors: Moon Ted
Published: February 2015

Techbits

More than 1,500 oil and gas professionals from around the globe converged on Abuja, Nigeria during 4–6 August of this year for the SPE Nigeria Annual Conference and Exhibition. With a theme "Innovating to Meet the Challenges of Global Energy Demand," the conference explored key industry issues such as finding sustainable solutions for the increasing worldwide energy demand and developing innovative ideas and technologies that will produce hydrocarbons more efficiently.

"Even though this conference was held in Nigeria and was organized by the SPE Nigeria Council, it was very much an international conference," said Charles Akhigbe, Drilling Fluids Specialist with Shell Nigeria's Wells Technology and Expertise Support Team and Chairperson of the Conference. "Of the 1,500 attendees, we had many expatriates from Asia, other parts of Africa, and Europe. The vast majority of these attendees were businessmen, representatives of Nigerian government regulatory agencies, banks, technical experts and industry professionals from all major oil and service companies, as well as some research institutions and universities."

The technical sessions began on 4 August and were sponsored by British Gas Exploration and Production Nigeria. Each technical session had two cochairs—managers and higher-level executives from major petroleum companies, some of whom are also members of the SPE Nigeria Council. "Participation in the Nigerian council cut across all of the oil companies and many service companies in Nigeria," Akhigbe said. "We had participants from Shell, ExxonMobil, Addax Petroleum, Total, Schlumberger, Halliburton, Afren, Agip, Chevron, Sapetro, Baker Hughes, Nigerian National Petroleum Corporation (NNPC), Oando, Nigerian Petroleum Development Company (NPDC), Platform Petroleum, Global Energy, and Midwestern Oil and Gas."

The technical sessions included 48 papers spanning all upstream disciplines, from drilling and completions to geosciences, HSE, and management. "There were also case studies, and most focused on wells and field experiences outside of Nigeria. The feedback I received was that the technical sessions were all of high quality," Akhigbe said. In fact, in a survey after the conference, 68% of responders considered the technical content of the conference to have been very good or excellent.

"As is typical for our conferences, we gave an award to the best technical paper based on recommendations of the Technical Paper Committee," he continued. "The technical paper session chairs assess each presentation in their session and pass the assessment on to the Technical Paper Committee, who then investigates each assessment and determines the winner. The award this year went to Chukwuma Uguru, Shell Nigeria Regional Petrophysics Discipline Lead, who presented a paper titled "A Simple Analytical Model for Vertical Permeability Prediction."
New Thinking Boosts Maturing UK Continental Shelf
Authors: Sheehan John
Published: February 2015

With the record oil prices of recent years, major operators in the UK North Sea have been holding onto assets and extracting as much value from them as they can. Companies such as BP, Shell, Total, and Chevron are applying new technologies to increase recovery rates and prolong the life of their existing assets.

This is a reversal of the trend of just a few years earlier when smaller independents came in to the region and snapped up producing assets that were deemed noncommercial by some of the indigenous oil companies. As a result, the UK North Sea is now being given a boost by both the established players and the independents, which are also applying innovative thinking and technology to tap the basin's existing reserves.

Malcolm Webb, Chief Executive of Oil & Gas UK, the leading representative body for the UK offshore oil and gas industry, has always been wary of tales of the bigger players turning their backs on the North Sea.

"I would say the stories of the majors leaving the North Sea were always slightly overdone," he said. "I think what we saw was a rebalancing of their portfolios. We saw some rather good asset deals for the basin going ahead and newcomers like Apache and Talisman coming in, picking up older assets, and bringing in new vitality and reworking them. Underneath all that we saw a continuing determination of the majors to go on working the basin generally and they have continued to invest. I think the view they were on a mass departure route was always overplayed.

"I think there are very positive signs that they are continuing to invest. If we look at majors like Total, Chevron, and BP, it is very interesting that they are all involved in the West of Shetlands activity. Total is looking to take forward some significant investments out there and Chevron has made good discoveries there as well, so there is lots of activity going on. They are also active elsewhere in the central and northern North Sea."

Moves to Reverse Production Decline

The UK Continental Shelf (UKCS) has so far had approximately 38 billion bbl of oil produced and the consensus among geoscientists is that another 25 billion bbl are still in play. But there is an alarming 7% annual production rate decline on the UKCS, a rate that Webb says must be pegged back.
Technology Focus: Reserves/Asset Management (December 2008)
Authors: Rietz Dean
Published: February 2015

Technology Focus

As a consultant who routinely is asked to assist clients on reservoir management (through reservoir studies), it is sometimes surprising when the usefulness of reservoir studies is questioned. First, it should go without saying that a reservoir study should be embarked on only to answer specific questions such as:How much oil or gas will be recovered from a particular asset?Can the same amount be recovered with less investment?Can more be recovered by use of optional operating approaches?

But the real question is, Why conduct a study in the first place? After all, once we find the asset, the reservoir properties (e.g., its size and the rock and fluid characteristics) are "what they are" and we cannot change them. Can we affect recovery by managing the reservoir, or must we simply accept what we get?

This brings us to a simple comparison with hurricanes. Earlier this year, the Houston area was impacted significantly by Hurricane Ike. Hurricanes, like petroleum reservoirs, occur naturally, and the characteristics (the fundamental properties that define them) are unique to that entity and are uncertain. In both cases, however, we can use tools (such as numerical models) to project and forecast their future behavior.

In the case of Ike, the weather models forecasted landfall in the vicinity of Galveston—well in advance, which enabled making decisions and taking action. To save lives, much of the anticipated impact area was evacuated. In addition, relief supplies, equipment, and personnel were prepositioned (out of harm's way) to respond quickly. The result was fewer casualties than experienced with earlier devastating hurricanes and an immediate response to begin the recovery process.

Just like preparing for the inevitable landfall of a hurricane, companies can plan for the inevitable depletion of a reservoir. Reservoir models, for example, can and do help identify more-efficient methods of hydrocarbon recovery. So, why are studies performed and reservoir-management strategies implemented? There are two main reasons: to improve recovery efficiency and/or maximize the return on investment of a particular asset. Our industry has the technology and the know-how.

Reserves/Asset Management additional reading available at the SPE eLibrary: www.spe.org

SPE 112932 • "Simplified Country-Entry Risk-Assessment Model for Global Petroleum Investments" by Surya Rajan, SPE, Marathon Oil Company, et al.

SPE 113260 • "Reservoir Management of the Gullfaks Main Field" by Saifullah Talukdar, SPE, StatoilHydro, et al.

SPE 111717 • "Real-Time Reservoir Management From Data Acquisition Through Implementation: Closed-Loop Approach" by Saeed M. Mubarak, SPE, Saudi Aramco

Additional reading available at OnePetro: www.onepetro.org

OTC 19644 • "International Risk Management" by Daniel V. Murphy, Systech International
Technology Focus: Bit Technology and Bottomhole Assemblies (December 2008)
Authors: Mensa-Wilmot Graham
Published: February 2015

Technology Focus

Performance Drilling—Taking the Next Big Steps

Drilling continues to be pushed into harder, deeper, and sometimes depleted environments. In addition, well profiles have become more complicated. As a result, footage drilled per bottomhole assembly (BHA) and rate of penetration (ROP) usually are low. These issues, if left unattended, will drive up drilling costs exorbitantly. Solutions are needed that will increase both footage drilled and ROP.

Researchers focusing on these issues have identified three key findings. First, performance improvement is a drilling-system problem (i.e., drill bit, BHA, and drive system) and is less dependent on individual components. Second, optimization of performance qualifiers (specifically footage, ROP, vibrations control, directional effectiveness, and borehole quality) is not an exclusive process. Third, real-time identification and remediation of drilling dysfunctions are critical to the drilling process.

The design and selection of drill bits must evolve from a feature-based approach to a technology-driven process. Drill-bit manufacturers need to move away from the current "me, too" approach, when it comes to product development. Local field knowledge, in terms of dips and behaviors, is critical and must be incorporated into BHA design. The BHA-design process must be fast, practical, and reliable. Drive systems (e.g., rotary-steerable types, mud motor, and turbine) must be selected on the basis of their effectiveness and relevance to project success. In this effort, rig specifications, operational hydraulics, formation drillability, and well profiles must be considered also. Offset performances should guide, but not drive, decisions made for subsequent wells.

Real-time data acquisition and interpretation are critical for the industry's next big steps in drilling performance. These data will guide the drilling process, in terms of anticipated formations, identification of dysfunctions, and parameter selections. As an industry, we have all the pieces—we need to bring them together quickly, to solve the puzzle.

Bit Technology and Bottomhole Assemblies additional reading available at the SPE eLibrary: www.spe.org

SPE 112647 • "A Systematic Approach to a Better Understanding of the Concentric-Hole-Opening Process Utilizing Drilling-Mechanics and Drilling-Dynamics Measurements Recorded Above and Below the Reamer" by Ian Thomson, Baker Hughes, et al.

SPE 112731 • "Optimization of Deep-Drilling Performance With Improvements in Drill-Bit and Drilling-Fluid Design" by Alan D. Black, SPE, TerraTek, et al.

SPE 115395 • "The Use of the Industry's First 3D Mechanical-Caliper Image While Drilling Leads to Optimized Rotary-Steerable Assemblies in Push- and Point-the-Bit Configurations" by Junichi Sugiura, SPE, PathFinder Energy Services, et al.
Multidiameter Tools Deliver Lower Cost Per Foot
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 112785, "Multi-Diameter String Tools Deliver Lower Cost- Per-Foot in Demanding Rotary-Steerable Applications," by Steve Barton, SPE, Wayne Jones, SPE, and Rick Young, ReedHycalog, and Helge Rorvik, SPE, Halliburton, originally prepared for the 2008 IADC/SPE Drilling Conference, Orlando, Florida, 4-6 March. The paper has not been peer reviewed.

Use of hole-opening tools in conjunction with rotary-steerable systems (RSSs) has increased dramatically in the past few years. Although excellent performance has been delivered with the mainstream commercial tools, alternative options have been developed to enable an RSS to drill the pilot hole in conjunction with a string tool to open the hole in a single run. The most popular current option involves a weight- or hydraulic-actuated under-reamer. However, fixed-blade, multidiameter reaming tools have been developed recently for use within rotary-steerable (RS) assemblies.

Introduction

Hole-opening tools fall into two main categories: eccentric and concentric. Eccentric reamers are fixed reamers that are dominated by bicenter drill bits or "wing-like" string reamer tools using polycrystalline-diamond-compact (PDC) cutters. They are developed for applications where hole enlargement is required but where the tool has to pass through a smaller-diameter restriction than that of the final hole size. The concentric tools are more diverse and range from fixed designs such as concentric drill bits and string tools (that could be either PDC or roller-cone cutting structures) to more-complex tools that open on demand by either mechanical or hydraulic control.

The growth in the use of hole-opening devices over the last few years was driven predominantly by the growth of deepwater drilling. The lessons learned from innovations in the deep water have extended those applications to shallower waters and even to selected land wells. Hole-opening-while-drilling devices have enabled operators to set larger strings of casing deeper in holes where hole stability, lost circulation, and high-pressure zones are a constant problem. This has the advantage of eliminating trips while leaving sections of open hole exposed over shorter durations, as well as providing a larger annulus for better cement jobs. The ability to reach extremely deep reservoirs with 12 1/4-, 10 5/8-, and 8 1/2-in. wellbores enables operators to run larger and more complex production strings, and this in turn has had an enormous effect on exploration-and-production economics.
Technology Focus: Production/Facilities (December 2008)
Authors: Skeels Brian
Published: February 2015

Technology Focus

Subsea processing is one of the most interesting technologies being introduced to the oil and gas industry. Treating the production flow at the seabed opens up opportunities to more-remote oil and gas reservoirs around the world. This operation is especially important because the industry is running out of reservoirs that are easy to produce, meaning that the focus is placed on how to produce oil and gas from longer-offset offshore fields in deeper reservoirs with difficult bathymetry.

A growing number of subsea multiphase pumps have been in operation around the world for several years to address less-than-ideal natural-reservoir-drive conditions. This growth has been followed by successful installation of subsea separation in the North Sea to address less-than-ideal flow characteristics and production of sand and unwanted byproducts. These technologies are being combined at a systems level to optimize reservoir recovery and management. Recent startups of combined subsea-separation, -boosting, and -injection systems offshore Africa, Brazil, and the deepwater Gulf of Mexico are adding to subsea processing's maturity and widespread acceptance.

Subsea processing continues to take steps into the future with project sanctions that use gas/liquid separation and oil/water separation. The next generation of processing systems will focus on more-compact solutions that will be well suited for deepwater applications. In addition, considerable effort is being made in the area of raw-water injection, low-/no-oil-fraction discharge, and subsea gas compression, all promising great potential for greater hydrocarbon extraction, saving the costs for additional surface infrastructure.

Production/Facilities additional reading available at the SPE eLibrary: www.spe.org

IPTC 12377 • "Plant Integrity and Reliability are the Keys To Improving Profitability" by S.D. Kapusta, Shell, et al.

SPE 115074 • "Corrosion and Hydrate Control in Wet-Sour-Gas Transmission Systems" by J.J. Moloney, SPE, Baker Hughes, et al.
Offshore-Connectivity Solutions for the Oil and Gas Industry
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 117254, "Offshore Connectivity and Ultra-Long Tiebacks Solutions for Oil & Gas," by A. Lecroart, R. Michel, and J.P. Odier, Alcatel-Lucent Submarine Networks, originally prepared for the 2008 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 20-22 October. The paper has not been peer reviewed.

The oil and gas industry is forced to go into deeper water further offshore to find new oil or gas. At the same time, the industry is placing more emphasis on integrated operations driven from onshore control centers. Highly reliable communications solutions are required to fulfill these objectives. Large bandwidth and low latency links between offshore facilities and the shore are essential for communications to all company personnel and contractors engaged in the offshore development areas. The full-length paper describes overall solutions to address these needs and reviews available technologies.

Introduction

Exploration and production of offshore fields is evolving and makes use of various modes of communication. Many oil companies are establishing operations centers where technical expertise is located. Telecommunications from the field to these centers is becoming critical, and solutions exist to make communication both efficient and dependable, with a choice of different technologies listed in Table 1 in the full-length paper.

Dry/Dry Solutions

The dry/dry solutions adapt the traditional shore-to-shore telecommunication application so that it can be used with different types of offshore assets such as a fixed platform or floating assets such as a tension-leg platform, a spar, or a floating production, storage, and offloading vessel (FPSO). One would prefer ring or loop architectures connecting each asset with its own spur by use of a branching unit (BU). The system is designed to allow the platforms to be independent and limits the number of risers per asset to one, compared to a simple daisy chain. For the last-mile connection, a dynamic riser is required to access floating assets, while a simple J-tube may be sufficient with shallower fixed structures. Another complexity may come from the use of fiber-optics (FOs) rotating joints because the latest generation of FPSOs tends to adopt a turret architecture, allowing the vessel to rotate freely. In most cases, studies are required to validate and qualify the riser design according to the requirements of the structure and the local weather conditions. A second approach is to equip an umbilical with fiber and allow the last-mile connection to take place subsea with a combination of wet-mate connectors and subsea manifold. In this case, a special cable termination is provided allowing remotely-operated-vehicle (ROV) handling of the wet-mate connector by use of a length of flexible hose. Both approaches are valid and will solve the last-mile issue adequately.
Cryogenic Technology for Processing High-CO2 and -H2S Gas Reserves
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 12708, "Controlled Freeze ZoneTM Technology for Enabling Processing of High CO2 and H2S Gas Reserves," by J.A. Valencia, P.S. Northrop, and C.J. Mart, ExxonMobil, originally prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3-5 December. The paper has not been peer reviewed.

Global natural-gas reserves increasingly are reported with significant CO2 and/or H2S content. Concentrations of 20 to 40% are not uncommon. Commercialization of such resources poses significant economic and technical challenges. Approximately one-sixth of ExxonMobil's hydrocarbon resources are categorized as sour gas. With these volumes, ExxonMobil has the industry's largest sour-gas resource base and has more than 50 years experience in managing sour gas.

Introduction

Monetization of lesser amounts of saleable methane/hydrocarbons while at the same time producing, removing, and disposing of major quantities of acid-gas contaminants calls for technologies that can reduce capital and operating costs. The proper disposal of these contaminants adds to the challenge. Release of CO2 to the environment is not desirable, its geosequestration is a much better alternative, and it would be better yet if it can be turned into a product stream to be sold or used for enhanced-oil-recovery (EOR) purposes. Similarly, alternatives for the disposal of H2S are needed because the conventional conversion to elemental sulfur led to the saturation of many markets. While there has been a recent resurgence in the demand for sulfur, uncertainties about wide-spread demand sustainability encourages the development of alternative H2S-disposal options.

The cryogenic technology, developed at ExxonMobil Upstream Research Company, is being advanced to the commercially ready stage in response to these needs. The first choice for many separations in the gas industry are those that take advantage of the simplicity provided by differing relative volatilities and phase behavior and are implemented by flash drums, separators, and distillation and fractionation towers. In the presence of methane, and to yield sales-quality gas, such separations imply very low, cryogenic temperatures of −120°F and lower, depending upon the operating pressure. CO2 solidifies at these low temperatures. The experimental measurement and analysis of CO2-solidification conditions in the presence of methane were pioneered in 1954. Shortly thereafter, a new process was proposed for freezing CO2 from natural gas by flashing a cooled gas stream into solidification conditions and using a cyclonic device to separate the resulting slurry into solid CO2 and liquid methane.
Conversations: Globalizing SPE Awards
Authors: Fattahi Behrooz
Published: February 2015

President's column

As I write this, we have just completed our Annual Technical Conference and Exhibition. A highlight of this event is always the presentation of international awards to our members for their technical and professional contributions.

SPE's international awards recognize the outstanding achievements of members who have given outstanding levels of technical knowledge, time, energy and expertise to SPE and to advancing the industry. These awards are particularly prestigious and meaningful because they are conferred by peers. As SPE has grown globally, we have made special efforts to ensure that the awards program engages our worldwide membership. Yet we know that many deserving individuals have not yet been recognized for their work. Although we have seen significant increases in the geographic diversity of the award recipients since 2001, we know we can and must do more to publicize our awards program to nurture global participation. A good start is to ensure that members understand the nomination and selection process.

The timing of this column is fortunate, since nominations for the 2010 awards are due no later than 15 February.

I'd like to discuss three important points about our awards program:How SPE goes about selecting award recipientsWhat you can do to prepare a nomination that will most effectively present the accomplishments of your colleague to the selection committeeWhat SPE is doing to improve the awards process

Award Selection Process

The selection of the SPE international award winners requires a huge volunteer effort. First, our members must step up to nominate their peers. These nominations are reviewed by the respective awards committees (15 of them!), made up of members from throughout the world who have the technical or professional qualifications relevant for the particular award. In 2009, 50% of award committee members were from outside the US, reflecting the makeup of our membership. Each award committee operates independently of the others, and does not know the geographic locations of the recipients selected by other committees. Each committee makes its selection only on the basis of the nominations received for its award. The committees are charged with identifying the most qualified recipient from among the nominations received. We do not have a quota system based on regions.

To further increase the number of international candidates, SPE expanded its regional awards in 2006 to include technical awards and additional service awards. The regional award recipients are automatically added to the nominations for the comparable international awards in the following year. The geographic distribution of the recipients changes from year to year, depending on the number of nominations submitted from around the world and the quality of the nomination information.

Note that, above, I said that committees select award winners from among the nominations received. So, first you have to nominate somebody. That leads to my second point: preparing an effective nomination is essential.
Legends of Production and Operation
Authors: JPT staff _
Published: February 2015

During the 2009 SPE Annual Technical Conference and Exhibition in October, JPT honored eight industry pioneers of production and operations for their outstanding contributions. As 2009 SPE technical director for Production and Operations, I was honored to host the luncheon and present awards to the attending recipients. Satish Pai, vice president of Worldwide Operations with Schlumberger, spoke on behalf of his company, which made substantial contributions to the event.

Production and operations is known as the backbone of the E&P industry. Simply put, it pays the bills. It involves complex mixtures of ?uids and compounds, utilizes energy to extract more energy products for everyone's use, and frequently also produces unwanted byproducts.

A concise history of production and operations helps bring its advances into perspective:

In the storage and transportation area, it began as dikes and ponds for storage, and barrels loaded onto wagons or rail cars. It progressed into storage tanks and transportation by trucks. It has since evolved into the use of pipelines.

Measurement has gone from the strapping of tanks to meters, lease automatic custody-transfer units, and, most recently, to intricate chemical ?ngerprint and compositional measurements with physical attribute identi?cation.

While much early production ?owed naturally, more advanced means of arti?cial lift have become necessary to extract ?uids with increasing ef?ciency.

Stimulation methods have gone from bullet perforation, through the use of nitroglycerin, to acid and other chemical means. It now includes various forms of hydraulic fracturing, gravel packs, and the like. The latest means are taking advantage of more sophisticated ?uids and proppant materials, as well as more precise measurement and placement methods.

It includes development and utilization of secondary and tertiary means of recovering hydrocarbons, including water?ooding, steam injection, chemical ?oods, surfactant ?oods, and microbial injection, to name a few techniques. There is no doubt that advances in these methods have greatly improved the pro?tability of many a ?rm.

As the costs of power and scarcity of labor continue their rise, production and operations personnel have used their innovative senses to stay ahead of the curve. New techniques and a "can do" attitude have resulted in many creative ideas, turning into items that the industry now simply cannot do without.

The legends, and countless others like them, are quite special. They may be known as petroleum engineers. However, much like the makeup of SPE, there may be a little mechanical, chemical, electrical, civil, or industrial engineer in them, too, as well as an understanding of geosciences, operations management, and economics.

The JPT Legends of Production and Operations program recognized remarkable achievements and eight extraordinary people—people who deserve our gratitude for making our jobs easier and everyone's life better through their efforts to improve productivity. Our hats are collectively off to you.
Technology Focus: Production/Facilities (December 2009)
Authors: Skeels Brian
Published: February 2015

Technology Focus

Reviewing papers to highlight in this year's feature, I was struck by the widespread embrace of novel technologies used at the macro and micro levels. This upsurge of acceptance of new approaches in the oil patch is long overdue and welcome. Nanotechnology and microelectromechanical systems are finding their way from the laboratory to practical applications. In addition, the growing use of fiber optics as the high-speed conduit to satisfy the burgeoning demand for real-time information in process management and for inspection, maintenance, and repair, is making inroads to improve sensor technology by harnessing unique physical properties of light in extremely hostile environments in which more-traditional methods have succumbed. The papers noted this month also foretell that we as an industry are more willing to look at old problems in new perspectives—using new materials, chemical agents, and techniques to solve tough problems that, just a few years ago, conventional wisdom considered impractical or unsolvable by the "throwing more iron at it" method. The new decade holds some exciting new prospects that will, once again, revitalize the industry and push the "oil peak" further out yet again.

Production/Facilities additional reading available at OnePetro: www.onepetro.org

SPE 123007 • "New Product for Inhibition of Calcium Carbonate Scale in Natural-Gas and Oil Facilities Based on Aloe Vera: Application in Venezuelan Oil Fields" by L.A. Castillo, PDVSA, et al.

OTC 19937 • "Plastic Liners for Hydrocarbon Transport: A Qualified and Cost-Efficient Alternative to Corrosion-Resistant Alloys" by S.J. Hall, Technip, et al.

SPE 120631 • "Determination of the Suitability of Reinforced Thermoplastic Pipe for Applications With Aromatic and Cyclo-Aliphatic Hydrocarbons" by B. Weller, Flexpipe Systems, et al.

SPE 120837 • "A New Microbiologically-Influenced-Corrosion Control Strategy in Low-Velocity Gas-Gathering Pipelines" by C. Smith, SPE, ICTC, et al.

SPE 123005 • "New Method for Extracting Oils and Greases From Produced Water Using Microwave Techniques" by R.H. Bezerril, Federal University of Rio Grande do Norte, et al.