bluuebunny/crossref_metadata_2025 huggingface dataset:
Guest Editorial: Forces That Will Shape Intelligent-Wells Development
Authors: Mathieson Derek
Published: February 2015

This year, the oil industry celebrates the 10th anniversary of intelligent-well completions, a revolutionary technology that has grown from a vision in the early 1990s to an industry-changing reality today. As the technology moves into its second decade, it is an appropriate time to reflect on the factors that have shaped the evolution of today's product lines and to consider the emerging market themes that will drive the next generation.

The origin of intelligent wells was prompted by a number of factors in the late 1980s:The first generation of subsea wells was moving into production decline and presenting many challenges in the execution of strategies to restore rates.Deepwater subsea wells, in which intervention would be prohibitively expensive, were being planned.Drilling-technology advances were leading to the development of complex wells, including horizontals, multilaterals, and extended-reach.

In effect, well-construction capability had outpaced the tools and workflow of production management, presenting a set of technical hurdles for well and production engineers to overcome. The challenge was to remotely monitor and control different sections or zones within a wellbore without the need for costly intervention. This need eventually would become the definition of "intelligent wells" and culminated in the installation of a surface-controlled reservoir-analysis-management system in 1997.

Market Hurdles

The first generation of intelligent-completion technologies consisted of a range of integrated electrical or electrohydraulic systems that included both sensing and control capabilities. These initial systems were complex and costly, and they were subject to a number of early field failures. In addition, all but a few users were unconvinced of the actual value proposition and were uncertain about how to express that value in a clear business case for each well. Survival of the technology was challenged initially by market-imposed hurdles of reliability and economic viability. Both of these themes remained dominant over the first 5 years of evolution and led to two clear decisions about development of the second generation of products: focus on all-hydraulic solutions to mitigate risk and focus on simple open/close-type control in subsea wells to avoid intervention and justify the economic case.

Thus, from around 1998 to 2003, most intelligent-well installations were simple open/close hydraulic valves, predominantly applied in subsea wells in the North Sea and the Gulf of Mexico. This period produced a rich set of reference material on economic modeling of active reservoir-management technologies and, more importantly, led to a cultural change for many of the major oil service companies, as they began to embed reliability-engineering practices into the development of oil tools.
Technology Update: Top-Drive Casing-Running Tool Solves Tough ERD Problems
Authors: JPT staff _
Published: February 2015

Over the past 15 to 20 years, top-drive technology has brought substantial improvements in efficiency and safety to drilling operations. However, casing-running methods have evolved more slowly and have not taken advantage of all the potential offered by top-drive drilling. Weatherford International has designed its new Overdrive system for running casing and drilling with casing to make full use of the weight and power of top drives (Fig. 1). The system won a Spotlight on New Technology Award at the 2007 Offshore Technology Conference.

This top-drive casing-running system was used recently by Shell to land casing on bottom at more than 18,200 ft depth on a troublesome North Sea extended-reach-drilling (ERD) well with hole restrictions caused by inability to clean the hole completely.

Torque-Drive Tool

The centerpiece of the technology is the torque-drive tool that combines several conventional casing-running tools into one—power tongs, main hoisting elevators, bails and single-joint elevators, a fill-up/circulation tool, and a weight compensator. All system operations are remote so that no personnel are required in the derrick or on the rig floor, resulting in a significantly lower safety risk (Fig. 2). The removal of equipment and scaffolding from the rig floor also creates a safer work environment.

The torque-drive tool is connected below the rig's top drive and can be run with any topdrive system. To run casing, the tool's integral bails and single-joint elevators are used to retrieve each joint or stand of casing, lift it into the derrick, and lower it into position for makeup. The torque-drive tool is then hydraulically clamped onto the casing, and the connection is made up using the rotational power of the top drive to transfer the torque through the torque-drive tool and casing connections.

A key component used in conjunction with the torque-drive tool is an integral electronic-load cell called the torque sub, mounted at the top of the torque-drive tool and used to measure the makeup torque of the casing connections. The sub is independent of the top drive and measures true torque, as opposed to conventional techniques that calibrate torque from the voltage that supplies rotational power to the top drive. This new level of accuracy is especially important when making up premium connections, which require torque-turn monitoring and a very low margin of torque-measurement error.

Once the connection is made up, the driller can instantly perform a number of operations as needed, including fill-up of the casing string while lowering, and simultaneous circulation, rotation, and reciprocation of the entire casing string. This combination enables the driller to overcome virtually any unexpected hole problems, such as ledges, lost-circulation zones, shallow-water flows, and swelling formations. This greatly enhances the ability to run the casing string to bottom in a predrilled well.
Overview: Intelligent Fields Technology (August 2007)
Authors: Gomersall Sam
Published: February 2015

Intelligent Fields Implementation: Why Is It Taking So Long?

We have been talking about intelligent fields or digital oilfield matters for some time, and while a significant number of papers have been written on the subject, mainstream application of the technology is patchy. Given the benefits from making better use of our data, why is it that the broad application of the digital oil field has not yet happened? Having been involved over the last 5 years or so, I see five inhibitors.Not enough focus on people and process—It is too easy to see the digital oil field as a new software product. In reality, how data is used in various processes, how workflows could change, and how people interact with data are fundamental to achieving the benefits of the digital oil field.Seeing the digital oil field as a single product—In reality, digital oil field is all about integration: integration of existing software, integration of data sources, and integration of data. This integration requires clarity of the architecture, the data flows, and the output requirements.Aiming for a fully linked integrated model before addressing fundamentals—It is key to start with appropriate instrumentation, data collection, surface control and data acquisition systems, and data conditioning to achieve early benefits from effective visualization and simple analysis. More-complex linking of integrated asset models should wait for "Phase 2."Lack of scalability—Often, assets develop solutions to address the immediate local business need without giving due consideration to being able to scale the solution to other assets. I fully support business-unit-led developments, but a corporate guide is required to ensure that they fit with the overall strategy.Difficulty in sustaining momentum—Enthusiasm, commitment, and resources at build stage can fall away if a key individual moves. Even a fully implemented system can be difficult to sustain if it is not applied consistently across assets.

Being aware of these traps and working to address them provides significant opportunity for wider mainstream application of digital oilfield technology over the next few years. Like you, I look forward to it.

Intelligent Fields Technology additional reading available at the SPE eLibrary: www.spe.org

SPE 104161 "Advanced Production Monitoring" by Martijn Hooimeijer, Shell Global Solutions, et al.

SPE 104227 "Smart-Well Completion Utilizes Natural Reservoir Energy To Produce High-Water-Cut and Low-Productivity-Index Well in Abqaiq Field" by Nashi M. Al-Otaibi, SPE, Saudi Aramco, et al.

SPE 105374 "A Novel Approach of Detecting Water-Influx Time in Multizone and Multilateral Completions Using Real-Time Downhole Pressure Data," by G.H. Aggrey, Heriot-Watt University, et al.

SPE 105618 "Smart Wells: Experiences and Best Practices at Haradh Increment-III, Ghawar Field," by Ibrahim H. Al-Arnaout, Saudi Aramco, et al.
Ormen Lange Subsea Production System
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 18965, "Ormen Lange Subsea Production System," by Thomas Bernt, Hydro, and Endre Smedsrud, FMC Technologies, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May.

The Ormen Lange field, in the Norwegian Sea, approximately 100 km off Norway, is within the prehistoric Storegga slide area with water depths reaching 850 m in the main production area. The gas will be produced from up to 24 subsea wells. The well fluid will be transported to the Nyhamna plant through two 30-in. multiphase lines. After processing, the dry export gas will be transported from the onshore plant through a new 42-in. pipeline by way of the Sleipner riser platform and further through a new 44-in. pipeline to the gas-receiving terminal in Easington, England.

Introduction

Fig. 1 shows the development concept selected for Ormen Lange, which comprises a subsea tieback to an onshore processing plant at Nyhamna. Conceptual engineering of the subsea production system was initiated in 2002. The main contracts for subsea-equipment supply, umbilical fabrication, and template installation were awarded between the autumn of 2003 and the summer of 2004. The main part of fabrication and testing took place during 2004–05, with the subsea templates installed offshore in late summer 2005. Umbilical A and the remaining subsea equipment were installed during the summer of 2006, and the first subsea tree was installed on Template A in December 2006. Completion of the first subsea well on Template A was scheduled for spring 2007, and subsea production startup was scheduled for autumn of 2007.

Subsea-System Configuration

With the large geographical extent of the Ormen Lange reservoir and the risk of reservoir segmentation, the subsea-system design has a high degree of flexibility, with four planned template locations. Therefore, a phased-development scheme was chosen. The phasing and location of the subsea wells will be timed to maintain plateau production as the field depletes.

Initial Development. The initial sub-sea development consists of two eight-slot production templates (Templates A and B), approximately 4 km apart in the main production area. Each tem-plate is tied back into the two 30-in. multiphase pipelines to shore. As Fig. 2 shows, these lines are interconnected through a pipeline-end-termination (PLET) system.

Two main control umbilicals link the onshore plant to the subsea production system; one is connected to Template A and the other to Template B. A cross-over-control umbilical interconnects the two production templates, providing redundant hydraulic supply to all the subsea wells.

To prevent hydrate formation, all wells are injected continuously with monoethylene glycol (MEG) through two 6-in. pipelines from the onshore plant. One line is connected to Template A and the other to Template B. A 6-in. crossover-MEG line interconnects the two production templates for added flexibility.
Overview: Unconventional Recovery (August 2007)
Authors: Norris Stephen O.
Published: February 2015

In the year 1419, Filippo Brunelleschi entered a competition to solve the most daunting architectural and engineering challenge of his time: designing and building the Dome of the Cathedral of Florence. The problem was that when the building was designed in the previous century, no one had any idea about how such a dome would be built (imagine that). To further complicate matters, buttresses were forbidden by the city fathers, internal scaffolding was undesirable, and the use of concrete had long been forgotten, which meant the dome had to be built out of bricks. Worse, his rival, Lorenzo Ghiberti, who was appointed coadjutator for the project, publicly mocked his plans and called them unfeasible.* (Think about that the next time you have a bad day at the office!) Fortunately for Florence and for Renaissance architecture, Brunelleschi endured the hardships and technical challenges to design and create one of the world's most famous and admired structures.

Today, we are faced with a daunting challenge: How can we supply the world with the energy our economies demand and, at the same time, reduce the emission of greenhouse gases, burn cleaner fuels, and improve air quality in our cities?

In this section, we will look at new technologies that hold at least a promise for meeting this challenge: simultaneous coalbed-methane production and CO2 sequestration, gas production from hydrates, and the use of hydrogen as a fuel for automobiles.

Certainly, we do not have all of the answers yet, and we will need to rely on innovators, like Brunellschi in the 15th century, to provide ingenious and unprecedented solutions. But with dogged determination, a little patience (it took 16 years to build the dome), and plenty of public education and support, I think we can make a difference that will improve the lives of many generations to come. Imagine that.

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

SPE 100674 "Data Analysis of Barnett Shale Completions" by B. Grieser, Halliburton, et al.

SPE 101109 "Changes in Completion Strategy Unlocks Massive Jurassic Coalbed Methane Resource Base in the Surat Basin, Australia" by R.L. Johnson Jr., SPE, Queensland Gas Company, et al.

Available at the OTC Library: www.otcnet.org

OTC 19090 "Electrical Collection and Transmission Systems for Offshore Wind Power," by Jim Green, National Renewable Energy Laboratory, et al.

* Wikipedia: http://en.wikipedia.org/wiki/Filippo_Brunelleschi and http://en.wikipedia.org/wiki/Florence_Cathedral. Accessed 18 June 2007.
Economics of Hydrogen Production From Natural Gas
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 101703, "The Hydrogen Economy: Economics of Hydrogen Production From Natural Gas," by D. Seddon, SPE, Duncan Seddon & Associates Pty. Ltd., prepared for the 2006 SPE Asia Pacific Oil & Gas Conference and Exhibition, Adelaide, Australia, 11–13 September.

Hydrogen is a principal fuel for high-efficiency fuel-cell vehicles that produce zero emissions. Hydrogen-fuel-cell vehicles can be fueled competitively with conventional fossil-fuel vehicles if hydrogen is produced in large central facilities with access to low-price natural gas. In times of high oil price, the production cost of hydrogen should be comparable to the price of petroleum fuels. Although improvements to the technology of production are being researched, breakthroughs will not make a major difference to the production costs. Great unknowns are the cost of hydrogen transport and delivery and the distribution pressure required.

Introduction

Hydrogen from sustainable nonpolluting sources such as wind or solar energy is touted as the transport fuel of the future. The cost of hydrogen production from such sources is very high and is uneconomic given the price of electricity produced by these methods. Conventional wisdom assumes that fossil-fuel-derived hydrogen will be used in the interim. Natural gas is an obvious candidate for this role. Small-scale hydrogen production is unlikely to be economic and to be viable; production needs to be focused on large-scale hydrogen production.

A series of engineering-concept studies for hydrogen production on a large scale has been published by the US National Academy of Science (NAS). Rather than using methanation as a step in hydrogen production, the NAS study used an alternative approach with a pressure-swing-absorption (PSA) unit to separate hydrogen.

The full-length paper focuses on development of a relationship between the production cost of hydrogen and the cost of natural gas for the mass production of hydrogen in a large central facility by use of the PSA method.

Technology

Hydrogen is produced commercially from natural gas for the chemical and refining industries. In the typical method to produce hydrogen, natural gas (methane) is steam reformed to produce a "synthesis gas" comprising hydrogen and carbon oxides [a mixture of carbon monoxide and carbon dioxide (CO2)]. The amount of methane "slipping" through the reformer is minimized by operation at high temperature and low pressure. Fuel for the reformer is provided by a fuel-gas-stream addition to the feedstock gas. The next step is to convert all of the carbon oxides into CO2 by use of the water-gas-shift (WGS) reaction.
Comments: Brazil's New Finds
Authors: Donnelly John
Published: February 2015

Editor's column

For an example of one of the new breed of successful national oil companies, look no further than Petrobras. Well known for technology expertise and innovation—the company has won two Offshore Technology Conference (OTC) awards for technical achievement—the Brazilian company is now making news for what could be some of the biggest oil discoveries in years.

Petrobras' Tupi discovery, located more than 150 miles in deep water off the Brazilian coast, has estimated recoverable reserves of between 5 and 8 billion bbl. That would make it one of the most significant finds in the past 20 years, according to analysts Wood Mackenzie, rivaling the 2000 Kashagan discovery in Kazakhstan and surpassing the largest deepwater finds, including those in the US Gulf of Mexico and offshore west Africa. Initial production of 100,000 BOPD could begin in 2010.

Petrobras has announced a series of oil discoveries in the Santos basin in recent months, including the natural gas field Jupiter and the subsalt field Carioca, which has drawn considerable speculation about its size. At this year's OTC, Petrobras Chief Executive Officer Jose Sergio Gabrielli, while acknowledging the importance of the deepwater discoveries, would not speculate on potential reserve figures.

If the promise of Tupi holds, Brazil would boost its reserves by 50% and join the ranks of the world's most significant producers. Already there is speculation that Brazil might eventually join OPEC. Petrobras' rise has been steady since it was partially privatized by the Brazilian government in the late 1990s. The country only recently became energy self-sufficient and now produces more than 2 million BOPD, almost 90% of it offshore. The company expects output to rise to 3 million BOPD by 2012 and 4 million BOPD by 2015. Petrobras believes that Tupi may be just part of a huge subsalt cluster extending hundreds of miles along the Brazilian coast.

Brazil's new oil finds will not be easy, or inexpensive, to develop. Although Brazil is considered a global leader in offshore development, the Tupi basin is located under 7,000 ft of water and then under 9,200 ft of shale and salt. Seismic imaging will be difficult and may hamper accurate estimation of reserves, and drilling challenges are common in subsalt. With regard to the Carioca area, Petrobras is at the beginning of its evaluation plan and will not have precise volume estimation until after finishing the plan.

The company's success could put a strain on already tight equipment and talent markets. Petrobras, which already has leased most of world fleet of vessels for deepwater drilling, plans to lease more and also hire thousands of upstream personnel as it creates a new division for subsalt drilling.
NMR Logging System Profiles Reservoir Fluids In Situ
Authors: Leveridge Robert
Published: February 2015

Technology Update

For many years, petrophysicists have been differentiating reservoir fluids by means of wireline logging instruments. However, this process has been time consuming, and for a number of environments, challenging. For nuclear-magnetic-resonance (NMR) measurements there have been further obstacles, such as job-preparation issues, availability of expert knowledge, and nonroutine workflows. The use of NMR fluid-identification methods, therefore, usually has been restricted to specialists.

Petrophysicists and reservoir engineers have long wanted to identify formation-fluid types, estimate their volumes, and determine their in-situ properties. A key goal has been to characterize formation hydrocarbons, regardless of variations in formation water salinity, thin beds, or low-contrast pay zones. With such information, it becomes possible to make a continuous log of oil viscosity for completion optimization, to determine fluid-storage volumes by means of lithology-independent porosity measurements, and to determine residual oil saturation in all mud types. An additional objective has been the ability to take measurements in rugose boreholes, or in zones with thick mud cake.

A new-generation NMR wireline logging tool developed by Schlumberger is able to meet these and other needs. Called the MR Scanner, the tool uses a multifrequency, multiantenna, deep-reading measurement at logging speeds up to 3,600 ft/hr to perform precise radial profiling of fluids surrounding the borehole (Fig. 1). Tool performance is unaffected by hole rugosity or variations in lithology, and measurements are obtainable regardless of borehole size or geometry, with axial resolution as good as 7.5 in. Most important, the use of the tool saves rig time because all measurements are made simultaneously.

A variety of quick-look outputs in user-friendly formats are made available onsite, including oil and water saturations, total and effective porosity, bulk volume irreducible water, crude oil and brine transverse relaxation time (T2) distributions, and hydrocarbon-corrected Timur-Coates permeabilities. In addition to T2, the longitudinal relaxation time (T1) is available for vuggy porosities, or in zones containing light hydrocarbons.

Tough Tests Prove Technology's Value

Recently, a North Sea operator needed to determine if gas condensate, light oil, and water were present in a well drilled with oil-base mud. While that was challenging enough, the operator also wanted to identify the contact level of these fluids, if present. Conventional logs had been run in the well, but the interpretation results were inconclusive, largely because of the invasion of oil-base mud filtrate.
Pioneering Oilfield Technology
Authors: Reid David
Published: February 2015

Management

Talk to industry old-timers about technological changes in the oilfield decades ago and their comments will likely be low-key, despite where they worked geographically or for which companies. While technology has evolved dramatically in the last 50 years, there was not a steady stream of "eurekas" echoing innovations. Instead, workplace-changing big ideas only bubbled to the surface every now and then.

We now have a decidedly quicker pace of innovation. Imagine going back in time—even only 20 years—and telling operational personnel that in 2008 one major oilfield service company currently has more than 230 technologies in active development.

This proliferation of new product development has delivered remarkable new efficiencies to rigs while requiring that management gain an enhanced understanding of how brand-new technology fits into overall drilling operations and how to best introduce the technology.

Innovation as Part of the Whole

The importance of innovation, in terms of how it goes beyond new product capabilities, is illustrated by a recent roundtable of representatives from majors, independents, and oilfield service companies, addressing the ramifications of technological innovation. Topics ranged from influences on the innovation process to where innovation fits in mergers and acquisitions, from the always critical technology adoption challenge to risk mitigation—all key management issues that transcend what is going on in the laboratory.

As a result of forward-looking management at companies, innovative R&D is not occurring in a corporate vacuum. Rather, potential innovations are "valued" at technology forums where presentations are given on a company's latest trends. From feedback out of the forums, tools and systems are refined and new ones developed, enabling operations personnel to produce better results out of existing assets or to find new assets.

In other words, the purpose of these presentations or fact-finding is, or should be, to discuss where investment money ought to be best-focused regarding the impact on current or new product lines, so that R&D actually makes a drilling performance difference—not simply introducing new technology for technology's sake. Because the development of new technology for field usage can be extremely expensive, these informational exchanges include focusing on which technologies can feasibly become immediate introductions and which are long term.

Clear Understandings

Developing and implementing new oilfield technology demands a clear understanding of how the overall process should work to be genuinely effective. Specifically, instead of a general game plan about taking ideas from concept to customer usage, management needs to delineate new product focus along the lines of delivering diversity, quality, and value. In so doing, each new technology or comprehensive drilling solution should ideally include technically advanced, field-proven systems that increase drilling efficiency; enhance health, safety, and environment programs; and maximize customers’ lifecycle economics.
Technology Focus: Formation Evaluation (August 2008)
Authors: Kennedy Martin
Published: February 2015

Technology Focus

There is a perception in our business that we have a poor track record of introducing new technology. At various times, I have seen unfavorable comparisons with pharmaceuticals and personal electronics. Is this fair? Consider two examples of the introduction of new technology to well logging.

There are practical restrictions on which measurements can form the basis for a logging tool. Nearly all possibilities had been tried by 1960, at least in an experimental tool, and many have been in use ever since. The last measurement to enter service was nuclear magnetic resonance, which exploited an effect first demonstrated in 1946. Even for this technology, the potential had been realized in the 1950s, about the same time as the first laboratory instruments exploiting the effect went on sale. The medical profession began to make use of magnetic-resonance-imaging scanners in the early 1980s; shortly afterward, a logging tool was brought into service. This tool was not a great technical or commercial success, and it was another 10 years before a viable logging tool appeared. Nowadays, the measurement is routine and new applications are announced every year. Is this an example of us being slow on the uptake? Absolutely not—the potential was realized early, but several individual technical hurdles had to be overcome before it became a viable logging tool. For example, laboratories and hospitals are not constrained by space or power and can use powerful electromagnets (often superconducting). Those sources are not real-istic in the borehole environment, and small strong permanent magnets had to be developed before the effect could be exploited satisfactorily.

Consider individual components rather than a whole system. Microprocessors went downhole in the 1980s, having appeared only a decade earlier. The Intel 8080 processor, arguably the first commercial device that contained the functionality needed for a logging tool went on sale in 1974 (at a cost of USD 385). This time scale is similar to the time required for a novel digital audio-encoding technology to appear as MP3.

I could go on and on, but space is limited. A bit of self-criticism is a good thing, but claiming we are slow to introduce new technology is damaging and does not stand up to scrutiny. Papers highlighted here demonstrate how our industry is taking advantage of the latest technologies to find better answers and make more-informed decisions.

Formation Evaluation additional reading available at the SPE eLibrary: www.spe.org

IPTC 11201 • "Identifying Fluid Type and Contacts in Carbonate Reservoirs" by Hsin-Yi Tseng, ExxonMobil, et al.

IPTC 11308 • "Carbonate-Rock Physics: Analytical Models and Validations Using Computational Approaches and Laboratory/Log Measurements" by Shiyu Xu, ExxonMobil, et al.

SPE 105353 • "Crosswell Electromagnetic Resistivity Tomography: Pushing the Limits" by M.L. Sanni, Saudi Aramco, et al.

SPE 105605 • "Nuclear-Magnetic-Resonance Logging: While Drilling, Wireline, and Fluid Sampling" by Douglas J. Seifert, Saudi Aramco, et al.
Estimation of Variable Fluid-Mixture Density With 4D-NMR Logging
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 109051, "Estimation of Variable Fluid-Mixture Density With 4D-NMR Logging," by Chanh Cao Minh, SPE, Schlumberger; Emmanuel Caroli, Total; and Padmanabhan Sundararaman, SPE, Chevron, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11-14 November. The paper has not been peer reviewed.

No technique is available to estimate the apparent fluid density measured by the density log. In wells drilled with oil-based mud (OBM), the near-wellbore-fluid composition and distribution can be very complex. Current practice for computing density porosity is to use an ad hoc constant fluid density. This method could lead to erroneous estimation of porosity. Radial fluid profiling with advanced magnetic-resonance tools provides radial information that can be inverted jointly with conventional 3D nuclear-magnetic-resonance (NMR) data to determine fluid mixture and radial distribution.

Introduction

Computing total porosity corrected for hydrocarbon effect from density/neutron logs gives an estimate of the hydrocarbon density when the matrix density is known. It assumes that the fluids are distributed uniformly within the investigated zones. Noting that near-wellbore fluids can vary radially and accounting for the different depths of investigation (DOIs) of the density and neutron logs enable computing total porosity in gas-bearing formations.

Density and NMR log data can be combined to estimate total porosity in gas-bearing formations in the so-called DMR technique. However, the various sensors assess the same fluids. In spite of their shallow DOI, each sensor has a distinct DOI and fluid-averaging scheme. For example, NMR has a shallow DOI on the order of 1 in. to a few inches and a narrow sensitivity zone in the formation. Classical nuclear tools have deeper DOIs, ranging from a few inches for the density tool to 1 ft for the neutron tool, along with much broader investigation zones than NMR tools. Even though NMR and density logs might agree in many circumstances, they may not assess the same fluids.

3D NMR is a standalone technique to evaluate near-wellbore fluids at a fixed DOI. In some cases, complex fluid mixtures including water, oil, OBM filtrate, and gas are observed. Slow logging speed and unfavorable vertical resolution prevent routine use of the technique to estimate total porosity.

4D-NMR logging adds a radial dimension and can deliver continuous fluid mapping at multiple DOIs called shells, typically at 1.5, 2.7, and 4 in., as shown in Fig. 1. The simultaneous processing of data from all shells is intended to optimize the fluid results.

Therefore, the variable fluid-mixture density can be estimated with 3D NMR at multiple DOIs and then used in the density-log-porosity computation, assuming that the matrix density is known.
Technology Focus: Subsea Technology (August 2008)
Authors: Salies Jacques B.
Published: February 2015

Technology Focus

The 2008 Offshore Technology Conference (OTC) was a record-breaking event: Attendance (75,000+, the highest in 26 years), participating companies, and, as a friend noticed, iron on the ground (I do not believe there are statistics on this issue, but…). Technical-session attendees were treated with projects and technologies for regions that ranged from the Arctic offshore to the deep water of east Asia—a rather broad array of applications.

The StatoilHydro subsea-to-shore gas development, Ormen Lange, received an OTC award for overcoming significant technical challenges to become Norway's deepest offshore development (800–1100 m). Although a subsea-compression system is yet to be developed to solve the challenges completely, Ormen Lange offers pioneering innovative solutions that will enlarge the industry's knowledge and improve confidence to face demanding tasks ahead that will test our ability to implement technological advances.

As of the first week of June, we reached record oil prices and an overall cost escalation in the oil industry. The implications are diverse. However, I believe it underscores how the ever-growing costs of drilling/completion/intervention rigs will put a very high burden on the development of any field, mainly subsea, that is heavily dependent on mobile offshore drilling units. Overcoming such cost escalation is a major challenge. At the same time, it is also a major opportunity for improvement.

To contemplate this quest for innovate solutions and the state-of-the-art technology in exploration and production, the highlighted papers vary from classical developments by Petrobras in its Roncador field offshore Brazil to Murphy Sabah's Kikeh field in Malaysia. In the case of Roncador, you will get to know an innovative pendulum method for installing manifolds in ultradeep water; in Kikeh, you will get an idea of the innovations necessary that were implemented to overcome the challenges of Malaysia's first deepwater development. In addition, a paper from BP outlines its successful track record of subsea developments, challenges facing the next generation, and the company's approach to technology to ensure success.

It is definitely an impressive collection of papers for their scope, content, and effect on the industry. I feel especially pleased to invite you to read them.

Subsea Technology additional reading available at the SPE eLibrary: www.spe.org

SPE 108970 • "Ormen Lange Subsea-Condition and Leakage Monitoring" by Jens Abrahamsen, Bjørge A/S, et al.

SPE 112723 • "Requirements for a Full-Drill-Through Subsea Wellhead and Tree System" by Sterling Lewis, SPE, ExxonMobil, et al.

Additional reading available at OnePetro: www.onepetro.org

OTC 19139 • "Managing Flow Assurance and Operation Risks in Subsea-Tieback System" by Shanhong Song, Chevron
Technology Focus: Health, Safety, and Environment (August 2008)
Authors: Veil John
Published: February 2015

Technology Focus

Health, safety, and environment (HSE) continue to be integral parts of all sectors of the oil and gas industry. Individual companies and industry associations strive continually to develop more-effective systems for managing HSE.

In the May 2008 issue, JPT editor John Donnelly wrote a column about how safety performance could be strained as worldwide drilling demand continues to grow at unprecedented rates. Nobody in the business wants to see this happen, but the safety (and health and environmental) challenges of operating faster and in more-difficult situations cannot be overlooked.

This year, as the HSE feature coordinator, was far more complicated than in past years. The JPT staff sent me more than 350 abstracts from HSE papers presented during the past year. Out of that thick pile, I had to select only a few for featuring here. I have encouraged splitting the three HSE disciplines into three, or at least two, separate features. The first gradual movement in that direction happened this year, as a new feature (CO2 Applications) was created, which considers carbon-capture and -sequestration papers. In a second small shift, this year's HSE feature offers papers for additional reading separately in each of the three areas. Your input regarding the split of these disciplines into separate features is encouraged, especially in the next reader survey.

Health, Safety, and Environment additional reading available at the SPE eLibrary: www.spe.org

Health

SPE 108551 • "Occupational-Health Aspects of Emergency Preparedness and Response" by D.S. Jones, ExxonMobil

SPE 111545 • "The Other Infectious Diseases of Concern" by Jean-Marie Moreau, ConocoPhillips, et al.

Safety

SPE 111563 • "Technology and Innovations Contribute to Safety and Efficiency in Storm-Disaster Recovery" by J.F. Mailey, SPE, Chevron

SPE 111845 • "Our Sustained Efforts—‘Hand and Finger Campaign’" by Rune Hobberstad, Halliburton, et al.

Environment

SPE 110118 • "Mercury-Removal Project: Issues and Challenges in Managing and Executing a Technology Project" by Muhamad Rashid Sainal, Petronas, et al.

SPE 111973 • "Emerging Issues in Produced-Water Management: Total E&P Norge's Approach" by Pierre Goud, Total, et al.

SPE 112861 • "Oil and Gas Producers’ E&P Waste-Management Guidelines" by E. Garland, SPE, Total, et al.
Development of a Security Process
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 108621, "Development of a Security Process To Meet the Requirements of Oil and Gas Companies in the Asia Pacific Region," by Matthew Quin, Chevron, originally prepared for the 2007 SPE Asia Pacific Health, Safety, Security, and Environment Conference and Exhibition, Bangkok, Thailand, 10-12 September. The paper has not been peer reviewed.

Security risks are some of the most pressing risk-management concerns of oil and gas companies in the Asia Pacific region. There is a strong requirement to develop a standard process that allows oil and gas companies to both manage security risks and meet their business requirements in the various countries in which they operate. The process, once developed, needs to be integrated into all relevant aspects of the business. The security process should be developed as a core feature of the operations-management system, allowing all levels of the organization to understand how security management fits into the business structure.

Introduction

Because of our dependence on oil, energy security is one of the most important issues facing the world economy today. The most common image of energy security is that of meeting the increasing demand for energy by ensuring a constant supply to consuming nations. However, there is an aspect of energy security that looks at the threats to the energy supply, the protection of the energy- supply systems, and physical protection of the people and assets that make up those systems. This second aspect is very much the subject of attention of security professionals working within the oil industry.

Security departments traditionally have not been seen as profit generators or business drivers and, therefore, have not justified the close attention of business managers and have not been well understood by them. It was the events of 9/11 that caused a major shift, when major oil companies with operations in the Asia Pacific region started to scrutinize more closely their security preparedness regarding the physical well-being of their personnel and assets. In a short period of time, security departments had to transform themselves from little-known entities into credible and accountable business units.

Security departments of major oil companies working in the Asia Pacific region have had to adapt to best serve the interests of one of the security profession's most challenging industries. The Asia Pacific region has the fastest-growing power sector in the world and is likely to be a growth engine of the world's economy throughout this century. Energy sources in the Asia Pacific region are fast replacing the maturing fields in more traditional regions, making security of the energy sources in this region an important issue. An effective solution is to modernize the role of a security department within the organization by developing a business-related process that enables an oil company to integrate its security function with all relevant aspects of its business operations.
Tar-Sands Drilling-Waste Management: A Clean Solution
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 112368, "Tar Sands Drilling Waste Management: A Clean Solution," by C. Nilsen, SPE, K. McCosh, SPE, and M. Kapila, SPE, M-I SWACO, originally prepared for the 2008 IADC/SPE Drilling Conference, Orlando, Florida, 4-6 March. The paper has not been peer reviewed.

The full-length paper presents novel technology for treatment of tar-sands drilling waste generated from steam-assisted gravity drainage (SAGD) and other tar-sands drilling operations. The continuous treatment process is based on hot-water addition, mixing, and separation techniques to reduce the viscosity and specific gravity of the bitumen to separate it from the sand. Treatment of cuttings with light to heavy bitumen contamination has shown this treatment method to be a simple and effective means of producing clean sand and recovering the bitumen component.

Introduction

Tar sands are sandstone formations saturated with bitumen or heavy oil. The sandstone is thought to remain water-wet in the formation and can be unconsolidated, with the sand grains held together mainly by the bitumen. Alternatively, the sandstone can be consolidated, with silica or carbonate cement holding the sand together and bitumen filling the remaining voids. The bitumen deposits were formed in the geological past from crude oil that migrated to the surface of the Earth. Weathering and chemical and biological processes resulted in loss of the light fractions, leaving behind the very-viscous, solid or semisolid heavy fractions. Typically, bitumen has a density greater than 960 kg/m3. Over the millennia, weather and geologic action covered the semisolid bitumen with layers of soil, and today, most bitumen and heavy-oil production comes from deposits buried more than 400 m below the surface of the Earth. Bitumen deposits are found in more than 70 countries worldwide, but 75% occur in Canada and Venezuela. In Canada, most of the oil sands are located in three major areas in northern Alberta, which hold at least 175 billion bbl of recoverable bitumen.

Where the heavy oil is thin it can be pumped out of the sands with progressing-cavity pumps (PCPs). To increase recovery, cold heavy-oil production with sand also is used in which sand is encouraged to enter the well by aggressive perforation and swabbing strategies. Removal of the sand with the heavy oil increases the formation permeability, expands the high-permeability zone as sand is produced, and prevents plugging of the near-wellbore region by asphaltenes or fines.
The Selfish Technology Gene - Discussion and Reply
Authors: Thuriaux-Aleman Ben , Thompson David
Published: February 2015

Discussion

To the Editor:

In their guest editorial, "The Selfish Technology Gene," (April 2008) authors Robert K. Perrons and Lew Watts provide an interesting scenario in which oil and gas companies would keep their technology investments proprietary. Arthur D. Little believes that this oversimplifies the current situation. The industry is characterized by a range of technology strategies (Fig. 1) and, while there may be a shift towards increased proprietary technology, the industry cannot afford to develop all its own technology in-house and will need to think carefully about which technologies should be proprietary.

In our work on technology management, we have highlighted that companies need to balance ownership of their technologies with opportunities for value creation from their investments. Keeping technologies proprietary prevents companies from extracting the full value of their technology investments. Shell is a case in point—it has made significant progress in extracting value from its technology investments by making some of these commercially available.

Although third-party technology suppliers have not always been responsible for the invention of new technology, they have excelled at refining the technology. While this is often not counted as technological development, it has played a great part in bringing new technologies to the right price point and reliability, something the oil companies could not afford to do on their own. For this reason, we do not see service companies being threatened in the near future.

The comparison with investments for a fabrication plant for chip manufacture in the article is unhelpful. Microchip manufacturers keep their technology proprietary because it influences chip design and performance, key factors in an industry in which differentiation and performance are very important. But a barrel of oil is a barrel of oil. Oil and gas E&P companies sell commodity products, and technology investments serve to access resources or reduce production costs.

The key area where Arthur D. Little feels that technology will be kept proprietary is in the development of unconventional reserves. This is because there is considerable uncertainty about pay-offs from this area and the potential for technology development.

Ben Thuriaux-Alemán, Manager, Arthur D. Little, UK

David Thompson, Senior Manager, Global Energy Practice, Arthur D. Little