bluuebunny/crossref_metadata_2025 huggingface dataset:
Stand Tall and Speak Up: Let's Make Championing Our Industry's Image a Personal Mission
Authors: Sprunt Eve S.
Published: February 2015

SPE is about you, the individual member. Over the last year, I have written a lot about how different aspects of industry image impact our industry's ability to operate. Now, let's make this personal and look at how industry image affects us as individuals and what each of us can do.

My daughter is now 25 years old. Recently, she reminisced about how, when she was 9 years old and in the fourth grade, I had visited her class to talk about my work. I was pleased that the visit had created such a strong positive memory. For my visit, I borrowed an SPE Magic Suitcase, which holds simple equipment to demonstrate the fundamentals of porosity, permeability in sand, oil sources and traps, and gas- and waterdrives (www.spe.org/web/suitcase/default.html). One demonstration that I thought these 9- and 10-year-olds would understand illustrated the concept of porosity. You can put it together yourself, using an empty container, granular material such as sand, beads, or marbles, and a container with water. Show the children the empty container. Then fill the container with granular material and ask them if it is now full. Then show them how you can add water to the "full" container. I also talked to them about what I enjoyed about my work.

Your section may have a Magic Suitcase that you can borrow. The Aberdeen Section has an active program using the Magic Suitcase to encourage children to take interest in science and engineering and to promote the oil and gas industry to educators and students at school career events. A slide show that is part of the Magic Suitcase materials is available at SPE.org. We are currently developing new pre-packaged presentation kits that our members can use in classroom visits or with civic groups. We want to make it easy to provide information to today's students about the importance of energy in our everyday lives and about the outstanding career opportunities for young people in our industry.

Talking with your children, other family members, and friends is a good way to start working on improving our industry's image. It also has the benefit of helping them better understand your personal role.

For the last couple of years, in conjunction with my job managing research in alternative energy, I've circulated news tidbits on alternative energy technologies within Chevron. One of my colleagues told me that he had shared some of this information with his daughter, a doctor in San Francisco, who works with the homeless and, with her friends, has modified a minivan to run on used vegetable oil. His daughter had previously chided him about his choice of occupation. However, he shared with her information on energy alternatives and convinced her that Chevron was serious about considering alternatives, thereby making her more favorably disposed towards his employer. This illustrates how little things can make a difference. My friend was pleased that just a small amount of information had made a difference in his relationship with his daughter.
Overview: Unconventional Recovery (August 2006)
Authors: Norris Stephen
Published: February 2015

I was inspired by a recent broadcast of All Things Considered on Natl. Public Radio and began to think of our industry and what could possibly make a difference in the world—if we, like Bill Gates, had an optimistic belief in technology and management combined with the vast resources of the petroleum industry. Is it possible for us to eliminate some of the top energy-related "diseases"?

The production of greenhouse gases certainly would be high on the list, regardless of whether you believe it is responsible for the recent global-warming trend. (Most of us would agree that it is at least a contributing factor.) So, is it "naïve overreaching" to think that we can affect such a gargantuan problem with current or near-future technology? I think we can help. In this issue, the focus is on technologies that hold at least a promise of a solution, either by offering an alternative to dirtier fuels or by eliminating or reducing some greenhouse gases directly.

Although expensive to produce and technologically challenging, coalbed methane (CBM) is a clean-burning fuel with tremendous potential for replacing some of the more conventional and "dirtier" resources. CBM is found in nearly every sedimentary basin, and current production is limited only by economics, which is negatively affected by water disposal and low production rates. New advances in recovery methods, such as the use of horizontal production and injection wells, could yield huge increases in CBM production.

CO2 storage in deep underground reservoirs is not a new idea, but until recently, very little was known about the storage capacity and viability of such a practice. Recent computer modeling has led to an increased understanding of the trapping mechanisms and suggests optimal injection practices.

CO2 sequestration in gas hydrates may offer a viable long-term storage solution while liberating methane gas to use as fuel. Although still in its infancy, this unconventional technology holds tremendous potential for the industry—and the environment.

I hope you will enjoy reading these paper highlights; and with an optimistic belief in our technology and management and with our vast resources, I know we can make a difference!

Unconventional Recovery additional reading available at the SPE eLibrary: www.spe.org

SPE 100021 "A Screening Model for CO2 Flooding and Storage in Gulf Coast Reservoirs Based on Dimensionless Groups" by D.J. Wood, U. of Texas at Austin, et al.

SPE 100584 "Evaluation of the Technical and Economic Feasibility of CO2 Sequestration and Enhanced Coalbed-Methane Recovery in Texas Low-Rank Coals" by G.A. Hernandez, SPE, Texas A&M U., et al.

SPE 97266 "Depressurization-Induced Gas Production From Class 1 Hydrate Deposits" by G.J. Moridis, SPE, Lawrence Berkeley Natl. Laboratory, et al.
CO2 Storage in Natural-Gas-Hydrate Reservoirs Benefits From Associated Methane Production
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18087, "Environmentally Friendly CO2 Storage in Hydrate Reservoirs Benefits From Associated Spontaneous Methane Production," by A. Graue, SPE, and B. Kvamme, U. of Bergen; B.A. Baldwin, Green Country Petrophysics LLC; J. Stevens, SPE, and J. Howard, SPE, ConocoPhillips; E. Aspenes, SPE, G. Ersland, SPE, and J. Husebo, U. of Bergen; and D. Zornes, SPE, ConocoPhillips, prepared for the 2006 Offshore Technology Conference, Houston, 1–4 May.

Carbon dioxide (CO2) sequestration in natural-gas-hydrate reservoirs may offer stable long-term storage of a greenhouse gas with the additional benefit of methane (CH4) production. The sequestration process may thus offer large amounts of energy for the future while providing a more thermodynamically stable gas hydrate that is less sensitive to global temperature changes.

Introduction

CO2 storage in natural-gas-hydrate reservoirs by replacing the CH4 in the hydrate with CO2 has attractive potential because it would produce free natural gas and establish a more thermodynamically stable hydrate accumulation. Natural-gas hydrates represent an enormous energy potential because the total energy corresponding to natural gas entrapped in hydrate reservoirs may be more than twice the energy of all known coal, oil, and gas energy sources. Natural-gas-hydrate accumulations rarely are completely stable in a strict thermodynamic sense. Typically, the hydrate is trapped between clay layers or other low-permeability structures. Gas hydrate exposed to the seafloor will dissociate because of the very-low hydrocarbon content in the surroundings. Though some of the released methane will be consumed by biological and chemical ecosystems, the methane reaching the surface represents an environmental concern because CH4 is a more aggressive (approximately 25 times) greenhouse gas than CO2.

However, a more serious concern is hydrate-formation stability. Changes in local temperature and pressure conditions or surrounding fluids or minerals change the system dynamics and can lead to catastrophic dissociation. The Storegga slide offshore Norway was created by several catastrophic hydrate dissociations. The largest of these is estimated to have occurred 7,000 years ago and is believed to have created a massive tsunami. The environmental disaster related to such enormous amounts of methane released into the atmosphere can have dramatic effects on the greenhouse scenario. The replacement of natural-gas hydrate with CO2 hydrate will increase the stability of hydrate formations. The hydrate content in the Storegga area is still significant and estimated to be on the order of 1012 m3 distributed over 4000 km2. Hydrocarbon exploitation in hydrate regions creates some additional concerns. Drilling operations produce heat and risk of local hydrate dissociation.
Operations Management Extends Field Life of a Long-Distance Subsea Tieback in Ultradeep Water
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18830, "Innovative Operations Management and Flow-Assurance Strategies Extend Field Life and Increase Ultimate Reserves of a Long-Distance Subsea Tieback in Ultradeep Water," by Aditya Singh, SPE, and Kevin Hannaford, Total E&P USA, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May.

In 2004, the subsea fields comprising the Canyon Express system were declining and water-production rates were increasing. To halt the fast decline and extend the life of the field, flow-lines were reconfigured to separate the depletion-drive wells from waterdrive wells. A real-time production-management tool for enhanced production planning, monitoring, and trouble-shooting was implemented.

Introduction

The Canyon Express transportation system consists of two 12-in. flowlines running parallel from Camden Hills through Aconcagua and Kings Peak to Canyon Station platform. The three subsea fields—Camden Hills, Aconcagua, and Kings Peak—are in 6,200 to 7,250 ft of water. The Canyon Express subsea tieback, at 56 miles from Camden Hills to Canyon Station platform, is one of the longest subsea tiebacks in the Gulf of Mexico. Production from the fields is predominantly gas with condensate and produced water. The wells are tied together by means of a daisy-chain arrangement. Fig. 1 shows a Canyon Express schematic.

During midlife operations, increasing water production from waterdrive reservoirs (Aconcagua AC1 and AC2, Camden Hills CH1 and CH2, and Kings Peak KP1 and KP2) and declining reservoir pressures of depletion-drive reservoirs (Aconcagua AC3 and AC4) led to high liquid rates and lower gas rates. The declining depletion-drive wells were restricted by higher water rates and liquid holdup in the flowlines. To optimize production during this period of increasing water rates and declining gas rates, several production options were considered. Detailed flow-assurance analysis was performed for each of the proposed options, and a recommended solution was reached on the basis of clearly identified advantages and disadvantages for each operating scenario. Flow-assurance evaluations were used on a continuous basis for operations planning to optimize and maintain production during this period.

Evaluation of Late-Life Options

Scenarios of the operating conditions to be studied were defined. Sensitivities on arrival pressures, gas-production rates, and water-production rates were developed from time points in the production forecast for evaluating the possible late-life operating techniques. A matrix of cases to be evaluated was developed.
Kikeh Development: Malaysia's First Deepwater Development
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 19637, "Kikeh Development: Subsea-Equipment-Installation Challenges for Malaysia's First Deepwater Development," by G. Murray and D. Lowther, Technip Subsea 7 Asia Pacific, and A. Ledingham and T.J. Stensgaard, Murphy Sabah Oil Co. Ltd., originally prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed.

The Kikeh development, the first deepwater project in Malaysia, is offshore eastern Malaysia in the South China Sea with a water depth of 1320 m. Kikeh is to be developed with 34 wells, and initial production was in August 2007. The full-length paper discusses the offshore-installation-vessel selection process including the effects on the decision process of using local equipment vs. mobilizing deepwater construction equipment from other deepwater basins around the world. With deepwater Sabah being a greenfield deepwater basin, a number of challenges arose in relation to equipment availability within the region and logistics to support deepwater construction operations.

Introduction

While these types of deepwater subsea developments have been brought on production in other deepwater basins for a number of years, particularly in West Africa and the Gulf of Mexico, the Kikeh development, as a first for Southeast Asia, brought about a number of challenges to and specific requirements for both opera tor and contractor that necessitated close cooperation in terms of sharing of installation assets across a number of contracts associated with the Kikeh development to meet the overall project schedule.

Because of the nature of this type of deepwater subsea project, involving the supply and installation of flexible flowlines and risers, the engineering, procurement, construction, installation, and commissioning (EPCIC) contractor elected to use a joint-venture partnership to execute the project on its behalf. The project team was established in Perth, Western Australia, where all design engineering, procurement activities, and preparation of installation procedures were undertaken.

Offshore-Vessel Selection

The primary vessel-capacity requirements were crane-lift capabilities, flexible-pipe lay tensions, and overall deck-storage capacity to handle the products to be installed. To determine the installation-vessel requirements, some initial engineering was conducted to better understand maximum lift and deployment loads associated with the installation program.
Your SPE: A Year Is Too Short
Authors: Roodhart Leo
Published: February 2015

President's column

Time flies for SPE presidents; a year is nothing. Geologists know that very well, but I am a production engineer, so how could I know? As I assumed the post of SPE President on 24 September last year I felt, as I said in my maiden speech, an over-riding sense of awe and eager anticipation. Awe when I thought of the richness and diversity that our SPE represents, as well as my responsibility to the global membership and to our industry as a whole. Eager anticipation when I thought of helping to realize the Society's dreams at the beginning of the 21st century.

I started out with three key objectives: to grow membership in the developing regions to make SPE a truly global organization; to develop more online resources for members; and to reach out to the young, who are essential to the future of our industry.

However, the moment I started my Presidency, the credit crunch, as it was called then, hit the world and developed rapidly into a global financial recession. Many companies reacted immediately with travel bans and cost cutting, and the consequences of those were quite dramatic for SPE. However, the SPE Board and staff reacted very swiftly, bringing meetings and workshops to where the members are, in practical, lower-cost places. We also accelerated the use of new communication technology. During my acceptance speech in Denver, I made a joke about organizing an SPE conference in Second Life, so guess my delight when the Digital Energy Conference did just that.

Overall, I believe SPE will rise from this recession much stronger, with an even leaner cost structure and with a new habit of utilising new technologies like web streaming conferences, the use of Webex and Skype, and the creation of "virtual presentation rooms" in place earlier than planned. So in the end, I am proud of the resilience of our Society, which cannot claim to be unaffected by the downturn but which can claim to have continued to deliver excellent programs and to attract high-quality audiences at worldwide events. It seems that senior management in our industry still values SPE's offer when it comes to technology dissemination and learning. My grandmother used to say that the heavier the cross you are carrying, the stronger you get.
Technology Focus: Formation Evaluation (August 2009)
Authors: Harrison Bob
Published: February 2015

Technology Focus

Generally, the entire interval between the surface casing and total depth is logged, but far too often we neglect to take core. While the expense of coring and core analysis is not small, it usually is only a fraction of total well cost; yet it remains an uphill struggle to convince management that the project will benefit from the knowledge gained. With the quest for reserves leading to exploration for and development of reservoirs with ever-more-complex porosity systems at greater depths and higher temperatures where log responses become suspect, I would argue that taking core has never been more important.

There is no denying that logs provide greater statistical coverage of a larger volume; have a better depth reference; can identify fluid contacts, missed pay, and swept zones; measure reservoir pressure; and can be calibrated to seismic data for reservoir-property mapping. However, visual inspection and laboratory analysis of core provide many key data that logs simply cannot provide, with applications for every discipline.

Core confirms the lithology and mineralogy of reservoirs; calibrates estimates of fundamental rock properties such as porosity, saturation, and net thickness; and remains the only true measure of permeability. Core shows how fluids occupy and flow within the reservoir pore space; enables formation-damage studies; and supplies mechanical properties to allow faster and safer drilling and better-designed completions.

Despite issues with cleaning, storage, restoration to native state, and scaling up, core still provides the best estimates of many of the crucial inputs for accurate reservoir modeling, even though logging-contractor marketing literature would have us believe otherwise. Logs cannot characterize a reservoir if knowledge of the rock is absent, so subsequent modeling must rely on uncalibrated and unverified log-derived correlations and analogs. The inevitable consequence is greater uncertainty.

Formation Evaluation additional reading available at OnePetro: www.onepetro.org

IPTC 12837 • "Accurate NMR Fluid Typing Using Functional T1/T2 Ratio and Fluid-Component Decomposition" by Boqin Sun, Chevron Energy Technology, et al.

SPE 117728 • "Reservoir Rock Typing From Crest to Flank: Is There a Link?" by R.E. Mahmoud Basioni, Abu Dhabi Company, et al.

IPTC 12328 • "Data-Acquisition and Formation-Evaluation Strategies in Anisotropic, Tight Gas Reservoirs of the Sultanate of Oman" by H.J. de Koningh, SPE, Petroleum Development Oman, et al.
Evaluating Implications of Hydraulic Fracturing in Shale-Gas Reservoirs
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 121038, "Evaluating Implica tions of Hydraulic Fracturing in Shale- Gas Reservoirs," by J. Daniel Arthur, SPE, Brian Bohm, Bobbi Jo Coughlin, and Mark Layne, SPE, ALL Consulting, prepared for the 2009 SPE Americas E&P Environmental and Safety Conference, San Antonio, Texas, 23-25 March. The paper has not been peer reviewed.

Exploration, drilling, and production of shale-gas plays such as the Barnett, Fayetteville, and Haynesville have changed the unconventional-gas industry. Two technologies that enhanced shale-gas development are horizontal drilling and hydraulic fracturing. Hydraulic fracturing of horizontal wells completed in shale reservoirs often requires larger volumes of fracturing fluid than conventional vertical-well stimulations. Rapid development of shale gas across the country has created concerns about the use of infrastructure and about environmental effects.

Introduction

The Barnett-shale play began in the Fort Worth, Texas, area in the 1980s. Continued improvements in hydraulic-fracturing techniques and technology enhanced development of the Barnett shale. Development uses horizontal drilling and sequenced multistage hydraulic-fracturing technologies.

Another source of technological advances in horizontal drilling and hydraulic fracturing is the Bakken shale of the Williston basin in Montana and North Dakota, which produces more oil than gas. Each shale-gas basin has a unique set of exploration criteria and operational challenges. However, the combination of horizontal-well completions and sequenced hydraulic-fracture treatments has been crucial in facilitating the expansion of modern shale-gas development to other shale plays. The low natural permeability of shale has been the limiting factor to production.

Shale-Gas Geology

Shale gas is natural gas produced from shale formations, and these shales function as both source rock and reservoir for the natural gas. Typically, shale gas is dry gas composed primarily of methane (90% or more). However, some shale-gas formations do produce water.

Gas shales are organic-rich formations traditionally viewed as source rocks and seals for stratigraphic gas accumulations. The thin layers, as shown in Fig. 1, that make up shale result in a rock with limited horizontal permeability and minimal vertical permeability. Unfractured shales typically have permeabilities on the order of 0.01 to 0.00001 md, limiting production.

The natural matrix permeability of shale sometimes is overcome by natural-fracture networks that developed when overburden pressure was reduced as a result of erosion of overlying rock formations. Other tectonic activity also can cause a change in the pressure, creating additional fractures. Often, fractures are key sources of permeability, facilitating the migration of fluids through fine-grained rocks such as shales.
Technology Focus: Drilling Management (August 2009)
Authors: Cunha J.C.
Published: February 2015

Technology Focus

Last April, I had the opportunity to attend the VI Technical Meeting on Well-Engineering Risk Analysis, at Petrobras University, Rio de Janeiro, Brazil, dedicated entirely to risk management in the area of well engineering. That 3-day meeting gave participants an excellent opportunity to exchange experiences, disseminate know-how and current procedures, and discuss problems and critical developments in the area of risk management for drilling and completion operations.

I was amazed by the number of diversified works as well as the quality of the presentations, panels, and roundtables. Several topics related to drilling management were presented including risk management for well-control operations, risks involved in the implementation of new technologies, risk analysis for prediction of time and costs in deepwater drilling and completion, the effect of drilling costs on the evaluation of new exploration opportunities, and many others.

It is clear to me that drilling management is related closely to risk management. The correct assessment of all risks involved in drilling operations will provide better planning and consequently will improve operational results. Our featured papers bring some examples of better-quality results obtained through superior planning. Project managers, drilling engineers, drilling supervisors, and field engineers will all benefit from careful planning. As most of us should know by now: "If you fail to plan, then you plan to fail" (Saladis and Kerzner 2009).

References

Saladis, F.P. and Kerzner, H. 2009. Bringing the PMBOK Guide to Life—A companion for the Practicing Project Manager, 49. Hoboken, NJ: John Wiley and Sons.

Drilling Management additional reading available at OnePetro: www.onepetro.org

SPE 119287 • "Probabilistic Well-Time Estimation Revisited" by A.J. Adams, SPE, Nexen Petroleum, et al.

SPE 114797 • "Advanced Drilling Simulation Proves Managed-Pressure Drilling (MPD) Economical in Gasfield Developments in Western Canada" by Geir Hareland, SPE, University of Calgary, et al.

SPE 120848 • "Systems Approach and Quantitative Decision Tools for Technology Selection in Environmentally Friendly Drilling" by O.-Y. Yu, SPE, Texas A&M University, et al.

IPTC 12707 • "Automatic Calibration of Real-Time Computer Models in Intelligent Drilling-Control Systems—Results From a North Sea Field Trial" by H.P. Lohne, SPE, International Research Institute of Stavanger, et al.
HSE Management in a Drilling Environment
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 117813, "HSE Management in a Drilling Environment," by Andrew May, Alain Moonen, and Stewart Logan, Qatar Shell GTL, and Jackie Allinson, CW International, originally pre pared for the 2008 Abu Dhabi In ternational Petroleum Exhibition and Conference, Abu Dhabi, UAE, 3–6 November. The paper has not been peer reviewed.

Since the beginning of the Pearl gas-to-liquid (GTL) drilling activities in Qatar's North field in 2004, five drilling rigs have been used and, to date, it has been a 4-year, 3-million-man-hours lost-time-incident (LTI)-free operation. Recognizing the industry challenges of introducing large numbers of inexperienced staff on the drilling rigs, introduction of a pro-gram of proactive health, safety, and environment (HSE) management by engaging all levels of the organizations of the operator and contractors has resulted in a top-quartile HSE and operational performance.

Introduction

After drilling and testing an appraisal well in 2004 and a data-acquisition well in 2006, the Pearl GTL development campaign began in earnest with two rigs (one a new build) drilling over two offshore jackets. During 2008, a land rig was taken on contract to drill two water-injection wells to dispose of condensed water from offshore. Also in 2008, an ambitious project matured to perform simultaneous operations in a hydrogen sulfide environment, consisting of drilling and completing wells while simultaneously perforating, acid stimulating, and cleaning up precompleted wells from temporary decks on the platform jacket.

Creating an HSE-Enabling Environment

Creating an HSE-enabling environment that is conducive to open, honest, and no-blame relationships generating hazard-reducing ideas is a result of a mix of many elements that require continuous focus and buy-in.

The creation begins at the contract-tender stage where the minimum HSE requirements are set out as an initial qualifying hurdle and where the HSE performance of each contractor is reviewed during the evaluation process. Then, in the period between the award of the contracts and the start of operations, project-kickoff meetings with participation of the operator, drilling contractors, third-party contractors, subcontractors, and office and on-site staff are used as a vehicle to develop the "One Team" approach to HSE. Openness, honesty, mutual trust, and full commitment are the key requirements for all parties involved to accept HSE as a core value and have fully aligned HSE aspirations.

At the commencement of the operational phase, all the enabling elements of the preparation phases, including detailed hazard analysis and the generation of HSE cases, are approached with great enthusiasm. This enthusiastic approach is key and produces clear and effective outcomes.
Strategic Health Management
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 127068, ’Application the Strategic Health Management,’ by Filippo Uberti, SPE, Erasmo Macera, Simone Mortara, SPE, and Guillermo Gomez, SPE, Eni E&P, originally prepared for the 2010 SPE International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Rio de Janeiro, 12-14 April. The paper has not been peer reviewed.

Eni E&P works in complex operating environments, interacting with host communities and sharing their health and social problems. Strategic health management (SHM) introduces a systematic approach in each phase of the project life cycle to improve the health status of the workforce and their families and to promote/sustain lasting improvements to the health status of host communities. The approach has been used in various countries through initiatives aiming at development of local primary-health-care systems and/or control of specific endemic diseases.  

Introduction

The objective of the SHM process is to pay attention to priority ill-health determinants within the host community and participate in their solution. Health-needs priorities, which sometimes need to be addressed, urgently would be faced more effectively and efficiently if a bottom-up approach could be used in the identification and planning process. Meaningful project design could be devised and thus attract whatever funding that might be available.

Investment in community health programs should be among the primary responsibilities of the local government. Although the decision on where and how much to invest in community health programs could be a matter of debate, it is (in line with self-reliance and -determination principles) the full responsibility of local authorities.

Because the objective of cooperation is to support partner countries in the development and implementation of their existing health policies and community health programs, the industry operators may choose to assist the local governments at various levels and in different ways.

Such assistance may take the form of direct or indirect investment, or could occur through more-traditional philanthropic corporate contributions. In all cases, the decision on whether to invest and how much to invest is up to the company. Actually, the contribution of a strong private/public partnership to health-system development is essential for a socially responsible company.

Prioritize Stakeholders

Timely and lasting improvements in community health are difficult to achieve and do not occur passively. Members of industry, sharing common principles and a common vision, must be prepared to engage host governments and other key stakeholders actively in cooperative consultation to plan actions that can achieve the desired outcomes. Planning and coordinating such interactions are critical over the life of a project.
Comments: Global Demand Surge
Authors: Donnelly John
Published: February 2015

Editor's column

Energy statistics continue to confirm oil and gas industry conventional wisdom of the past several years—that global consumption shows no sign of stopping, which will put additional burdens on the industry and its people to pro-duce more energy amid challenging conditions.

Last year, world energy consumption grew 5.6%, the largest percentage increase year over year since 1973, according to the BP Statistical Review of World Energy 2011, a well-known annual report on energy data and trends. Demand grew for all forms of energy in all regions. This reflects a sharp reversal of what happened in 2009, when countries across the globe were feeling the effects of recession. That year, global energy consumption decreased for the first time in 30 years, but that appears to be just a temporary dip in a longterm trajectory of rising demand in both industrialized and developing countries.

Total consumption of energy surpassed the pre-recession peak of 2008, according to the BP report, and energy consumption is now growing faster than the world economy. China and India, whose demand did not slow during 2009, are showing an even stronger thirst for all types of energy. China’s share of global energy consumption now stands at 20%, making it the largest consuming country in the world, ahead of the US.

Average oil prices in 2010 were the second highest on record, but that did not deter demand growth. Prices for natural gas, though, which is a much less fungible commodity, varied from region to region. Gas prices remained weak in North America because of the enormous growth in shale production.

The outlook for gas appears bright. The International Energy Agency (IEA) recently offered the idea that the world could be entering a “golden age of gas” led by the growth in unconventional production. It predicts that over the next 25 years, 40% of global gas production will be from unconventional sources. Again, China is the leader. The IEA believes that China’s gas consumption could rise where it would equal total European Union demand by 2035.

An interesting phenomenon is the growth in shale oil in North America. The IEA recently revised its expectations for US oil production, and now predicts that US oil output will rise 1 million b/d by 2016 because of the increase in unconventional oil production, an offshoot of the shale gas surge. That figure could climb to 2 million or 3 million b/d by 2020, the IEA said. The suggestion is that the technology that has unleashed the shale boom could offer the same benefit for the oil side. The US Geological Survey estimates that the largest shale oil deposit in the US, the Bakken in North Dakota, could contain as much as 4 billion bbl of recoverable oil, and the Three Forks formation nearby could contain 2 billion bbl in recoverable reserves.
Growing Offshore Water Production Pushes Search for Subsea Solutions
Authors: Rassenfoss Stephen
Published: February 2015

There are strong arguments for moving water processing from deepwater platforms to the seafloor in many fields. There need to be, given the daunting challenges to doing so.

One of the prime targets is older offshore fields producing more water than oil. When the water treatment facility on the topside reaches its capacity, it puts a cap on oil output. The rising water cut increases the force needed to lift a production stream holding ever less oil, as the pressure in the reservoir declines.

Ultimately the natural force isn’t enough to lift the water and oil from deepwater fields, which will mean the end of production if nothing is done. “When you can’t get it to the surface, you are left with nothing, unless you have got a way to pump it,” said Tim Daigle, senior project engineer at Fluor Offshore Solutions. There are two ways to do that: Increase the lift with pumps, or reduce the load by removing the water on the seafloor and disposing of it there.

After nearly two decades of development and testing, the latter option is beginning to emerge as an alternative. Oil companies are turning to subsea processing for projects that are challenged by the economics, looking for ways to make them profitable, or to improve their results, said Mike Robinson, a sales and marketing manager at FMC Technologies, which is a leader in this area.

Statoil’s Tordis field offshore Norway shows the upside and downside of subsea water separation. The company predicted the combination of subsea water processing and improvements in the pumping system on its Gullfaks C platform would increase ultimate production by 35 million BOE, pushing the field’s recovery rate from 49% to 55%. The design is based on what Statoil learned from its earlier pilot test installed on its Troll C platform in 2001, which is still processing 50,000 bbl a day and reinjecting the water into an aquifer.

Rune Ramberg, chief engineer of sub-sea technology at Statoil, said there are many reasons for the Norwegian company’s push to develop subsea water treatment systems. It has long relied on subsea completions. Developing Arctic resources will require alternatives to offshore platforms, which are vulnerable to ice. And most importantly: “We are not making money transporting water,” Ramberg said.
Managing Use of Local Content in Upstream Oil and Gas
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 140870, ’Managing Use of Local Content in Upstream Oil and Gas,’ by Jessica M. Marshall and Mark A. Serwinowski, SPE, MetaVu, prepared for the 2011 SPE European Health, Safety, and Environmental Conference in Oil and Gas Exploration and Production, Vienna, Austria, 22-24 February. The paper has not been peer reviewed.

As new markets develop and host countries develop local-content policies and performance expectations, oil and gas development companies face increasing complexities in supply-chain integration of local content. In many instances, performance assurance with local-content-performance expectations is becoming a threshold for obtaining and/or maintaining a company’s social license to operate. This paper chronicles one company’s approach to leverage local content as part of their supply-chain-management strategy to grow capacity while managing and fulfilling stakeholder expectations.     

Introduction

Supply-chain management is becoming increasingly vital for ongoing operations in the upstream oil and gas sector. How individual organizations manage and train their suppliers can result in dramatic differences in performance. Given that, on average, upstream operators more-heavily leverage their suppliers, who these individuals are, what screening criteria they must meet, how they are managed, and how their performance is tracked are critically important questions.

In certain circumstances, use of local content to fulfill demanding schedules is not only encouraged from a social-responsibility perspective, but is a requirement for meeting deadlines. However, use of local content should be managed with a very specific engagement strategy to ensure that health, safety, and environmental performance expectations are not compromised.

Background

The use of local content (i.e., indigenous companies that conduct manufacturing or production services in the oil business), while required in cases of remote operations, can have positive benefits for the organization and for the host country/region. Effective use and training can result in transfer of knowledge, economic diversification, and long-term viability for the host region. But benefits also can be realized by the company.

While there are tangible benefits for the host country/region and for the organization, the use of local content should be managed proactively and be part of an overall supply-chain-management strategy. Five criteria have been established as key success factors.

Policy expectations and targets must be realistic and go hand in hand with capacity building

Content development must be based on global competitiveness, rather than preference

Contracting strategies are critical channels of content transfer and development

Content development must involve risk assessment regarding health, safety, and environmental standards, and regarding business risks including supply capacity, quality, delivery schedule, cost effectiveness, and profit generation
Spectrum: Great Rewards
Authors: Thakur Ganesh
Published: February 2015

President's column

As I approach the end of my term as SPE president, I reflect not only on the past year but also on what led up to this wonderful year. I think about how SPE has affected my life in so many ways, all of which stem from three simple decisions.

First was my decision to join SPE. How do individuals determine value, and why do they choose to belong to a professional organization such as SPE? For me, it was a natural decision. I would be working in one of the most important careers in the world; in what other profession can you make a difference in the lives of millions of people every day? It logically followed that I wanted to be the best I could in that career. I have always viewed SPE as the foremost professional association for those working in oil and gas exploration and production (E&P). With its many technical resources (including its unrivaled collection of technical papers, its respected magazines and peer-reviewed journals, and its excellent conferences); the commitment exemplified by its mission, vision, and values; and its ability to connect E&P professionals globally, SPE was the best association to help me achieve my goal.

Second was the decision to learn. Why do people seek continuing education, and how can a membership organization such as SPE meet their needs? I took continuing education courses to keep up with the advancements in technology and to continue to sharpen my skills to become more productive and prolific in my work. I was privileged to take SPE short courses taught by world-class professionals such as Dr. Aziz Odeh. I kept learning more and more, especially early in my career. During 1990–91, I started to teach a course on integrated petroleum reservoir management with Dr. Abdus Satter, and, later, we wrote a textbook on this subject that became popular in the industry and with many universities around the world. Although I learned a lot by taking SPE short courses, I learned even more from teaching courses attended by some of the best minds in our industry. I remember, for instance, a course in the 1990s that included Bob Schneider (he passed away a few years ago), retired from Shell, and W. John Lee, a very distinguished professor from Texas A&M now at the University of Houston. This was one of the best courses I have ever taught because we not only taught the course but we also facilitated an enriched discussion that led to a superb learning experience for all the participants, including me.
Advances in Measuring Permeability Address Shortcomings of Crushed-Rock Technique
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 152257, ’Advances in Measurement Standards and Flow Properties Measurements for Tight Rocks Such as Shales,’ S. Sinha, SPE, E.M. Braun, SPE, Q.R. Passey, SPE, S.A. Leonardi, SPE, A.C. Wood III, T. Zirkle, SPE, J.A. Boros, SPE, and R.A. Kudva, SPE, ExxonMobil Upstream Research, prepared for the 2012 SPE/EAGE European Unconventional Resources Conference and Exhibition, Vienna, Austria, 20-22 March. The paper has not been peer reviewed.

The most commonly used industry method for measuring permeability is the Gas Research Institute (GRI) technique or its variants, which involve the use of crushed samples. The accuracy of such techniques, however, is questionable because of a number of inadequacies, such as the absence of reservoir overburden stress while conducting these measurements. In addition to the questionable accuracy of crushed-rock techniques, studies have indicated that there is significant variability in results reported by different laboratories that use crushed-rock techniques to measure permeability on shale samples. The complete paper presents a robust steady-state technique for measuring permeability on intact tight-rock samples under reservoir overburden stress. These standards can be used to calibrate any permeability-measurement apparatus used on intact tight-rock samples, such as shales, to enable delivery of consistent results across different laboratories.

Introduction

For low-permeability reservoirs such as shales, the GRI method is popular because of the relatively quick times associated with the measurements as a result of the increased surface area available and because of the perception that measurements on intact low-permeability plug samples by use of well-established methods such as steady state or pulse decay could take such long times that it would make such measurements impractical. However, using crushed rock for measuring permeability has a number of inadequacies, resulting in skepticism associated with the accuracy of such measurements. Perhaps the most serious drawback of the crushed-rock method for measuring permeability, as presented in a number of studies, is the wide variability in results reported by different vendors, with results that could differ by as much as three orders of magnitude.

Shortcomings of GRI Technique of Measuring Permeability

The GRI, or crushed-rock, technique for measuring permeability is a relatively fast method for measuring permeability on low-permeability samples, but it has the following shortcomings.

Absence of Overburden Stress. The GRI technique is implemented on crushed rock samples, and, therefore, these measurements are not conducted at reservoir overburden stress. Ignoring the effect of overburden stress while measuring the permeability could lead to significant discrepancy between permeability measured in the laboratory and in-situ permeability.
Autonomous Underwater Vehicles Ease Deepwater-Field Integrity Management
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 22438, ’The Role of Autonomous Underwater Vehicles in Deepwater Life-of- Field Integrity Management,’ by Dan McLeod and John Jacobson, Lockheed Martin, prepared for the 2011 Offshore Technology Conference Brasil, Rio de Janeiro, 4-6 October. The paper has not been peer reviewed.

Integrity management of deepwater fields requires routine general visual inspections of critical infrastructure. To date, the only way to conduct general visual inspection is through the use of remotely operated vehicles (ROVs). Deepwater ROV spreads are large and heavy, requiring large support vessels and a significant number of personnel at sea. The capabilities of unmanned underwater vehicles have been enhanced through developments in autonomous technology, progressing to the point that autonomous underwater vehicles (AUVs) can now routinely conduct general visual inspection of subsea facilities.

Introduction

AUVs are smaller than ROVs, require less deck space, have fewer operators, and are free from precise-positioning requirements of the support vessel. Advances in autonomy, coupled with unique mission sensors, greatly reduce the human interaction required when collecting images of oil and gas underwater infra-structure. These factors dramatically reduce the operational cost of a deepwater inspection.

The Marlin AUV system recently completed a series of tests in the US Gulf of Mexico, demonstrating autonomous change detection of a fixed off-shore platform. Benefits of autonomous inspection include

Reduced cost of operations

Faster inspection

Automatic change detection

Georegistered inspection data

Simultaneous operations from a single support vessel

Large standoff distances from the facility being inspected

Increased safety of operations

Reduced environmental impact

Reduced specification requirements on support vessel

Subsea Integrity Management

A key element in any integrity-management program is regular in-service inspections. As the industry moves into deeper and harsher environments, challenges faced by operators include the high cost of subsea inspection and the limited inspection intervals available. Inspections provide a snapshot of the structural health of the system. An ROV inspection of a deepwater facility can provide visual evidence of structural degradation, impact damage, corrosion, valve damage, leaks, vibration, and other structural damage. Benchmarking the condition of subsea equipment following installation and tracking its status over time can provide a history of the deterioration rate.

Deepwater Inspection Tasks

Visual inspection of deepwater facilities routinely employs ROVs piloted by operators on the surface while recording high-definition video data. Video inspections include equipment that is often spread over many square kilometers, requiring the support vessel to maneuver for days. Inspection speed is totally dependent on the coordinated movement of the ROV and support vessel and on the skill of the ROV pilot.