bluuebunny/crossref_metadata_2025 huggingface dataset:
IOCs, NOCs Discuss Common Challenges, Developing Local Content
Authors: Henni Abdelghani
Published: February 2015

Summit review

How resource-rich countries can build sustainable economies through partner-ships with the oil and gas industry was the focus of a recent industry/government summit in Dubai. Key executives from national oil companies (NOCs), private firms, and governments met for 2 days at the National Oil Companies and Governments Summit held in Dubai in late September. Among the companies participating were Saudi Aramco, Kuwait Oil Company, Shell, Total, and ExxonMobil.

Opening the conference, the head of the International Energy Forum (IEF) advocated increased transparency of oil data from the region’s oil producers in the interest of stabilizing oil prices. “If you want markets to be stable, you should be working toward market transparency,” said Aldo Flores-Quiroga, secretary general of the IEF, an 89-member country organization that promotes global energy dialogue. He pointed to the differing oil demand forecasts of OPEC, the producers’ cartel, and the International Energy Agency, the group that represents oil consumers in advanced economies.

He noted that in the forecasts to 2035, there is a discrepancy of 30 million BOPD between the two. “Discrepancies like this matter,” said Flores-Quiroga. “What you estimate about demand will influence what you do about supply.”

IOCs Defend Themselves

In a panel session on developing resources and stimulating long-term sustainable growth, speakers from major international oil companies (IOCs) shared their experiences and strategies in developing local content and helping governments and NOCs achieve their objectives.

Mark Carne, executive vice president for Middle East and North Africa (MENA) at Shell Upstream International, said that the purpose of the summit was to discuss strategies to drive job creation and skills development, and to enhance country value. Instead of working toward achieving this goal, the oil and gas industry has adopted strategies against the development of a local labor force. “Adopting industry ‘best practices’ such as low-cost country sourcing and global framework agreements has meant, in some cases, that job creation opportunities have moved to other countries,” he said.
Research and Development at Universities: Worldwide Change in Petroleum Engineering
Authors: Braswell Gentry
Published: February 2015

The fundamental properties of hydrocarbons and the basics of drilling will always remain the same. Nevertheless, innovation in petroleum engineering by researchers at universities around the world is changing the face of oil and gas drilling and production in the 21st century. In addition to traditional approaches, technologies for enhanced production from mature fields; production methods for unconventional resources such as tight gas, methane hydrate, and heavy oil; and experimental nanotechnology applications today are critical and increasingly are a part of petroleum engineering research and technology development.

Schulich School of Engineering, University of Calgary, Canada

The upstream research at Schulich’s Department of Chemical and Petroleum Engineering concentrates on improving the exploitation of Canadian unconventional oil and gas resources such as heavy oil and bitumen, and tight gas formations. The department has a dozen research teams, said professor Brij Maini.

The In Situ Combustion Research Group specializes in laboratory and numerical simulation studies of the in-situ combustion of heavy oils, and high-pressure air injection in light oil reservoirs.

The faculty’s EnCana/Paleontological Society of Canadian Institute of Mining, Metallurgy, and Petroleum Endowed Chair heads the department’s joint industry project studying the geomechanics of shale gas. The CMG Foundation Chair in Reservoir Simulation is developing fast and reliable reservoir simulators for the recovery of oil, gas, and coal. The NSERC Industrial Research Chair in Heavy Oil Properties and Processing is researching the properties and phase behavior of heavy oil and solvents. Schulich’s SHARP (Solvent/Heat Assisted Recovery Processes) consortium is supported by 11 local and international companies.

The improved heavy oil science and technology group is studying various aspects of heavy oil recovery technology, including cold heavy oil production with sand, and solvent-based recovery processes and steam additives for steam injection-based processes.
Finding New Talent in a Talent Gap
Authors: Coton Simon
Published: February 2015

Talent & Technology

It is a truism that most long-dreaded events fail to materialize as catastrophically as predicted. For the global oil industry, the well-anticipated “great crew change” or the “talent gap” is not one of those false alarms.

By whatever name, the talent and skill shortage is here. And every sign by our measure is that the anticipated problems are both real and understated. Oil and gas companies today are more challenged than before to develop innovative strategies to find and train new talent. New solutions, such as poaching from other industries and canvassing for job seekers among returning veterans, have become increasingly successful.

The Problem Areas

Our firm has noted several challenging areas. They are:

A number of approved projects that were put on the back burner during the global recession have started to come back on line. Since they were approved years ago, the companies will want to hit the ground running, rather than spending time ramping up. Such projects will find the talent/skill shortage as bad as predicted.

Several of the hottest spots for exploration and production activity, such as Brazil and Iraq, are in need of new talent and expertise to meet their goals. Just rebuilding Iraq’s dated infrastructure, for instance, could take a giant share of the world’s graduating chemical, mechanical, electrical, and civil engineers for years.

The same could be said about Brazil, which has embarked on one of the largest development plans in its history. But its ambitious and well-funded goals show an estimated talent shortfall of 40,000 engineers for the foreseeable future. In these two hot spots and others, the shortage will be as bad or worse than predicted.

Many of the newer skill areas across the industry, whether in oil sands, tight gas, shale gas, shale oil, or ultradeep sea operations, need tomorrow’s experts and today’s expertise. But the talent is simply not available today. These new projects will also find the talent shortage a challenge.
Field Trials of Reservoir Nanoparticles Reveal Stability, High Rates of Recovery
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 142592, ’Industry First Field Trial of Reservoir Nanoagents,’ by Mazen Y. Kanj, SPE, Saudi Aramco, and M. Harunar Rashid and Emmanuel P. Giannelis, Cornell University, prepared for the 2011 SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 25-28 September. The paper has not been peer reviewed.

The promise of nanotechnology becomes limitless with the possibility of having functionalized molecular agents to illuminate the reservoir and intervene to alter adverse oil recovery conditions. The future reality of the reservoir nanoagents concept was laboratory and field demonstrated with the industry’s first building block nanoagents’ template. The industry’s first proven reservoir nanoagent template is introduced and demonstrated by means of a push/pull field trial in an observation well.

Introduction

A milestone achievement on the road to having in-situ reservoir nanoagents features an industry-first building block template named Arab-D Dots (A-Dots). The synthesis is proved to be very amenable for scaling up in support of a field operation.

Reservoir Rocks

The Jurassic Arab-D is the most prolific oil-bearing formation of the Ghawar field in Saudi Arabia. Ghawar (Fig. 1) is the largest discovered oil field in the world today. From its northern extremity, the field extends southward some 150 miles as essentially one long continuous anticline, approximately 25 miles across at its widest point. The Arab-D formation constitutes one of the main reservoirs of Saudi Arabia and is composed of reservoir-quality limestone and dolomite. The Arab-D reservoir has an average thickness of more than 200 ft. On the finer scale, it can be further subdivided into four major shoaling-upward carbonate cycles (Fig. 1).

The A-Dot Particles

A-Dots are carbon-based fluorescent nanoparticles. Carbon nanoparticles represent a unique class of nanomaterials that are generally synthesized through a hydrothermal treatment process. Analogous to their well-known cousins, fullerenes and carbon nanotubes, carbon nanoparticles exhibit interesting optical (and electrical) properties that may be exploited in oil and gas applications. A-Dots are developed with a functional stability to survive a lengthy transit in a harsh environment in an oil reservoir, which can be read and interrogated reliably when the nanoparticles are recovered. This translates into required stability at temperatures exceeding 100°C and salinities exceeding 120,000 ppm in total dis-solved solids in the presence of divalent (as well as monovalent) ions such as Ca++, Mg++, and SO4−−.
Preliminary Test Results of Nano-Based Fluids Reveal Benefits for Field Application
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 139534, ’Preliminary Test Results of Nano-Based Drilling Fluids for Oil- and Gasfield Application,’ by M. Amanullah, SPE, Mohammad K. Al-Arfaj, and Ziad Al-Abdullatif, Saudi Aramco, prepared for the 2011 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 1-3 March. The paper has not been peer reviewed.

The oil and gas industry is looking for small, chemically and thermally stable, biologically degradable, environmentally benign material to use in the design of smart fluids. Because of highly enhanced physiochemical, electrical, thermal, and hydrodynamic properties, nanomaterials are considered a promising material. Recently developed nano-based fluids were formulated to study the rheological and filtration properties and evaluate fluid suitability for oil- and gasfield application. Initial test results indicate that the newly developed nano-based drilling mud produces suitable high- and low-end rheological properties.

Introduction

Water- or oil-based drilling fluid is the first foreign fluid that contacts the reservoir zone of a borehole. Most muds contain particles that are part of the mud formulation. These desirable mud solids can cause severe formation damage in the presence of a poor quality mudcake. Moreover, the cutting debris generated while drilling may produce enough microsized and colloidal particles to cause severe formation damage if a poor quality mudcake is deposited on the borehole wall. Hence, drilling muds that are unable to form a well-dispersed, tight, thin, plaster-like external mudcake on the borehole wall can cause serious formation damage because of the formation of an internal mudcake.

Spurt loss associated with most of the mud systems is one of the notorious sources of solid-particle and particulate invasion in the vicinity of the wellbore. Fine particles coming into the drilling mud as a part of drill solids may also cause severe formation damage if the mudcake formed on the borehole wall is poorly dispersed, is very thick because of particle flocculation, and has highly porous fabric because of loose-fabric formation by the flocs, aggregates, and particles.

The thickness of the deposited mudcake is also a critical factor in many drilling and reservoir-engineering problems. Muds producing soft and thick cakes increase the potential of differential sticking and, thus, are not desirable for geological formations highly prone to differential sticking.
Integrated Completion Design for Horizontal Wells in Unconventional Reservoirs
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 147120, ’An Integrated Approach To Design Completions for Horizontal Wells in Unconventional Reservoirs,’ by R. Jain, SPE, S. Syal, SPE, T. Long, SPE, and C. Wattenbarger, SPE, ExxonMobil, and I. Kosik, SPE, Imperial Oil Resources, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed.

An integrated workflow was tested for designing completions for a heavy-oil-recovery process that involves injection and production through the same wellbore. To capture the effect of variations or uncertainties in reservoir and fluid-flow characteristics over time, the transient effects are particularly important while analyzing the long-term performance for these types of completions. The proposed integrated workflow involves initial screening and selection of flow-restricting completions that can meet the desired injection and production performance on the basis of a detailed wellbore-hydraulics-modeling tool.

Introduction

Producing heavy oil and bitumen involves technologies such as cold mining for shallower resources or in-situ viscosity reduction. The cyclic solvent-based process involves alternating cycles of injecting a viscosity-reducing solvent into the reservoir followed by production of a mixture of heavy oil and solvent, with reduced viscosity, through the same wellbore.

Many cyclic-process implementations are intended for use in horizontal wells. The completion design for such a process involves ensuring good solvent distribution into the reservoir during the injection phase to mobilize the resource along the entire wellbore and maximize the well length to reduce field-development cost. The process of injecting and producing from the same wellbore entails additional constraints on the completion design. One constraint is controlled injection distribution by use of flow-restriction devices such as orifices while maintaining a minimal pressure drop across the completion during the production phase.

Another challenge results from the adverse mobility ratio of the solvent mixture and bitumen during the injection process, which could result in viscous fingering. This fingering can cause wide variations in the solvent injection and may cause an undesirable pressure distribution within the reservoir, which, in turn, may affect solvent placement. Predicting such differential injection or a thief zone is difficult because of the inherent nature of instabilities associated with the fingering process.
Long-Term Gas-Hydrate-Production Test, North Slope, Alaska
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 22152, ’Evaluation of the Hydrate Deposit at the PBU-L106 Site, North Slope, Alaska, for a Long-Term Test of Gas Production,’ by George J. Moridis, SPE, and Matthew T. Reagan, SPE, Lawrence Berkeley National Laboratory; Heidi Anderson-Kuzma, SPE, East Donner Research; Yang Zhao, University of California at Berkeley; Katie Boyle, Lawrence Berkeley National Laboratory; and James W. Rector, University of California at Berkeley, prepared for the 2011 Arctic Technology Conference, Houston, 7-9 February. The paper has not been peer reviewed.

To investigate the technical feasibility of gas production from hydrate deposits, a long-term field test (lasting 18 to 24 months) is under consideration in a project led by the US Department of Energy. A candidate deposit involving the C-Unit in the vicinity of the PBU-L106 site on the North Slope, Alaska, was evaluated. The results indicate that production from horizontal wells may be orders of magnitude larger than that from vertical wells.

Introduction

Gas hydrates (GHs) are solid crystalline compounds of water and gaseous sub-stances that are described by the general chemical formula GsNH H2O. In the GH clathrates, the molecules of gas, G (referred to as guests), occupy voids within the lattices of ice-like crystal structures. If gas and H2O availability is not a limitation, hydrate deposits can occur in two distinctly different geographic settings in which the necessary conditions of low temperature, T, and high pressure, P, exist for their formation and stability: in the Arctic (typically in association with permafrost) and in deep ocean sediments. CH4 is the dominant GH-forming hydrocarbon gas in natural hydrates that occur in geologic media. Under standard T and P (STP) conditions, each cubic meter of simple CH4 hydrate releases, upon dissociation, approximately 164 m3 of methane and 0.8 m3 of H2O.

Classification. Natural GH accumulations are divided into three main classes on the basis of simple geologic features and initial reservoir conditions. Class-1 settings have two layers: a hydrate- bearing layer (HBL) and an underlying two-phase-fluid zone containing mobile gas and liquid water. A distinct feature of Class-1 settings is that the base of the GH-stability zone coincides with the bottom of the HBL. Class 1 is the most desirable target because it is the easiest to destabilize to release gas. In Class-2 settings, an HBL overlies a zone of mobile water. Class-3 accumulations have a single HBL with no underlying zone of mobile fluids.
Investigating Liquid Loading in Tight Horizontal Gas Wells
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 149477, ’Investigation of Liquid Loading in Tight Horizontal Gas Wells With a Transient-Multiphase-Flow Simulator,’ by Donald F.B. Jackson, SPE, SPT Group, and Claudio J.J. Virues, SPE, and David Sask, SPE, Encana, prepared for the 2011 Canadian Unconventional Resources Conference, Calgary, 15-17 November. The paper has not been peer reviewed.

Liquid loading occurs in gas wells when production declines to a rate that is insufficient to lift the associated liquids to the surface. Liquid holdup in the horizontal section may impair production before liquid loading in the production tubing becomes evident. Holdup in the horizontal section can lead to slug flow at the tubing and to early onset of liquid loading in the tubing. The results from a transient-multiphase-flow model were found to be consistent with data acquired from video logging. Sensitivity analyses were performed with several normalized trajectories.

Introduction

Technology applied in conventional reservoirs in offshore horizontal wells can be applied successfully in onshore horizontal wells in unconventional reservoirs. The Jean Marie formation is an Upper Devonian carbonate platform between two thick shale layers in the Greater Sierra area, approximately 90 km east of Fort Nelson, British Columbia, Canada. The formation has low porosity (averaging 6%), low water saturation (averaging 20%), and low permeability (less than 1 md to air). Formation depth ranges from 600 to 1500 m subsea—1000- to 1900-m true vertical depth. The formation is entirely gas saturated with a dry sweet gas (95% methane) and is variably underpressured, with initial reservoir pressures of 6 to 15 MPa.

The horizontal wells are drilled underbalanced to limit formation damage. Fig. 1 shows a typical well completion with 177.8-mm production casing set at the top of the Jean Marie formation. Gas is produced from the openhole portion of the completion. While drilling horizontally through the Jean Marie formation, the well trajectory is steered on the basis of gas-rate-while-drilling (RWD) data. The geologists maneuver up and down in inclination until a good permeability streak is indicated by a spike in flow rate from the RWD data. After reaching target depth, tubing (typically 60.3 mm) is installed and the well is brought on production. Typical gas- production rates for Jean Marie wells decline from an initial rate of 56×103 m3/d to 14×103 m3/d after 12 months and to 10×103 m3/d after 36 months.
Improved Riser Management Situation Awareness Through 3D Visualization
Authors: Jensen Gullik A.
Published: February 2015

Young Technology Showcase

As with many monitoring and decision support tools, riser management systems originate from the engineering community so may assume a large degree of domain knowledge. Unfortunately, this knowledge is not always found among offshore personnel, which prevents the full potential of the monitoring tool to be realized. This may have a negative impact on riser operations and, in turn, on drilling safety and efficiency.

The Kongsberg Riser Management System (RMS) is a real-time monitoring and decision support system for safe and optimum operation of drilling and workover riser systems. Recognizing the potential gap between what the system can do to enhance these operations and what the operator can actually make it do motivated the development of a new user interface for the RMS operator station. It differs from traditional RMS interfaces as it has been developed based on a virtual model of the riser and its environment in three dimensions. The model is built from the data available in the system for riser and vessel representation and is updated in real time to reflect the changing state of the riser based on real-time sensor measurements and advanced computations.

Through the new user interface, the operator can navigate in a virtual space to inspect different aspects of the current operational situation, either by taking a step back for overview, or by zooming in to examine the details. The advantage of this technology is the improved operator perception of the actual situation that contributes to enhanced situation awareness. Likewise, through real-time 3D visualization, the operator can take full advantage and maximize the results gained from all RMS system features.

In operation, the updated user interface presents the monitoring and advisory features of the system in a context that the operator can easily relate to. This makes the system better suited to contribute to a safer and more optimal operation of the riser system during the drilling operation.
Seeking Lower-Cost Ways To Deal With Fracturing Water
Authors: Rassenfoss Stephen
Published: February 2015

Unconventional Water

The management of water used for fracturing oil and gas wells is all over the map.

In Pennsylvania, most of the produced water is treated so it can be used again for fracturing, but some is cleaned to the point at which it meets the stringent requirements for river disposal.

In Texas, fracturing fluids generally use fresh water, and what flows back to the surface is injected into a deep disposal well.

A 2012 report, prepared by the Bureau of Economic Geology for the Texas Oil & Gas Association, titled Oil & Gas Water Use in Texas, puts the percentage of produced water recycled for fracturing in the Eagle Ford shale at 0%, and in the Permian Basin near Midland at 2%. In these arid regions fresh water is used by a wide margin. In the Eagle Ford, 20% of the water for fracturing came from brackish aquifers, and 30% in the Permian around Midland used water too salty to be potable.

Things change fast in these booming plays. But the lead author of the report, Jean-Philippe Nicot, a research scientist at the Bureau of Economic Geology of The University of Texas at Austin, said: “I don’t think those numbers have changed much. There is likely some reuse/recycling in all plays, so 0% is probably not correct, but close to it.”

For Michael Dunkel, director of sustainable development at Pioneer Natural Resources, past performance in places like the Permian is not a useful indicator of the future in an area where so many are looking for alternatives. “I am confident what we are seeing today is just at the starting gate and it will continue to evolve,” he said.

Given the thousands of unconventional wells drilled, this may seem to be a slow evolution, but the staggering scale of these formations, particularly in the Permian, means operators such as Pioneer are just moving from scattered exploration drilling to concentrated development.

“We will be drilling for 30-plus years out there,” Dunkel said. While he is confident the industry will change how it manages water for unconventional development, there are a lot of ways it can go from here.

The decisions hinge on a complex mix of variables, which can be boiled down to a simple imperative: What is the lowest-cost option? The correct answers will vary from region to region, and from company to company depending on factors such as the scale of a company’s operation.

Chesapeake Energy treats most of the water produced in its wells in Pennsylvania for reuse in fracturing with a small amount sent for disposal, said Rick McCurdy, manager of chemicals and water reclamation at Chesapeake Energy Corp. In south Texas most of the water is pumped from freshwater aquifers and produced water is injected into disposal wells.
Offshore Europe 2013 Looks to Next 50 Years
Authors: Parshall Joel
Published: February 2015

Conference review

SPE Offshore Europe (OE) hailed the first 5 decades of the North Sea oil and gas industry by looking forward to the next 50 years. It was a fitting theme for the biennial conference and exhibition held 3–6 September in Aberdeen as OE marked its 40th anniversary, a reminder of how the event has helped to shape the industry’s perspective almost from the first days of North Sea oil.

Sessions and speakers looked critically and hopefully at the North Sea industry, closely examining its many current and future challenges and presenting numerous scenarios and strategies for how it would survive and prosper. Some observers envisioned the North Sea sector strengthening the global oil and gas industry in the next half-century through continued production, the expanding resources of its supply chain, and the spread of its world-class expertise.

A plenary and 11 keynote sessions and the presentation of more than 100 technical papers and ePosters highlighted the conference, which also featured daily breakfast briefings and topical luncheons.

However, the event had a somber note. On 23 August, four offshore oil workers lost their lives when a helicopter flying them from their rig crashed off the Shetland Islands. Many of the presenters and speakers, including the Princess Royal, paid tribute to the four people and acknowledged the risks inherent in working offshore and the industry’s strong continuing commitment to safety.

Conference Chairman Malcolm Webb, chief executive of Oil & Gas UK, said that the United Kingdom oil and gas industry is the country’s greatest industrial success story in more than a hundred years and this year’s event served to underline that fact. “At the biggest Offshore Europe ever, we’ve addressed the key themes that will require industry focus to sustain activity in the UK Continental Shelf,” he said. “None of these is more important than safety.”

The Next Half-Century

Addressing the opening plenary session, the Rt. Hon. George Osborne MP, UK Chancellor of the Exchequer, stressed the continuing importance of the industry to the country.

“First, I recognize the vital role that oil and gas play in the UK economy and will continue to play for many, many years to come,” Osborne said. “Second, I also recognize that the oil and gas remaining in the UK Continental Shelf (UKCS) will be increasingly difficult and more expensive to extract, that this government commits to play our part in delivering the investment that’s needed. And third, I believe that the best way to support this industry and maximize the returns from this great national asset is by working together across the United Kingdom through mobilizing all of the UK’s resources and by pooling our risk to provide stability across the whole of the UK.”
Stark Realities of Managing Cybersecurity Risk
Authors: Drobny Chuck
Published: February 2015

Management

Worldwide, the cybersecurity threat is real and growing. The oil and gas industry’s technological critical infrastructure has been especially hard-hit, absorbing 40% of all cyber attacks globally. Yet the realities are not resonating effectively with industry executives, because many companies have yet to put comprehensive protection plans into action.

This issue is potentially so devastating that it figuratively shouts for a short course about the chances that companies are taking, what vendors and purported experts are advocating, the grave risks, the unvarnished truth about hackers and company vulnerabilities, and how waiting for disaster is a dead-end choice.

Largely because of its worldwide exploration and production scope and the vast population dependent on energy, oilfield companies cannot simply blend in with the landscape and become unrecognizable as a major cyber target. For example, Telvent, which makes a control system for smart grid networks, was recently hacked. Project files for its supervisory control and data acquisition (SCADA) system were accessed and malware was installed on its network in the attack.

Other attacks have occurred against Saudi Aramco, which required 10 days to get its network back online after a Shamoon Wiper malware cyber attack disabled more than 30,000 workstations in a supposedly politically directed action by a group of hackers called the Cutting Sword of Justice. In a costly move only possible with a sovereign nation, the company sequestered its entire network while determining the cause of attack and fully restoring service. Meanwhile, the Chinese military has been accused of attempts to hack all types of industries, with a particular focus on oil and gas, according to the Mandiant Intelligence Center Report.

Response Offerings

This disturbing news has had polar opposite effects. One is that the threat message is not getting through to many oil and gas companies. It is akin to a tree falling in a forest when nobody is there to hear the crash. Conversely, springing into action are vendors, so-called cyber experts, and conferences offering cyber-security solutions to the executives who are receptive to the message. With this growing demand for both information and installed protection, more companies are taking the cue that they need technical cyber expertise they do not have internally to survive the hacking they may have never expected (“Nobody would attack us. We are too small.”).

When companies do become engaged in seriously protecting their organization and its resources, the budget should not be arbitrary. Rather, it should be allocated on a basis commensurate with the spending on any other insurance or similar budget items. Benchmarking the traditional safety budget is a good approach, since it is typically proportioned over several years based on risks.  Similarly, in terms of perspective, physical or plant security offers comparable guidelines in allocating resources to both deal with the threat and its consequences.
Packer-Leak Repair: Slurry Design and Complex Coiled-Tubing Well Work
Authors: Denney Dennis
Published: February 2015

This article, written by Dennis Denney, contains highlights of paper IPTC 17091, ’Extending Mature-Well Life by Innovative Slurry Design and Complex Coiled-Tubing Well Work,’ by M. Hairi A. Razak, Aulfah Azman, SPE, and Haryat Timan, Petronas, and M. Heikal Kasim, SPE, and M. Fakhrurazi Ishak, Schlumberger, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.

A well in the South China Sea was diagnosed by ultrasonic and temperature logging to have a well-integrity problem, forcing the operator to shut in the well because the leak created a high tubing/casing-annulus pressure. Through-tubing well work was used because it is more economical than a full workover, particularly for wells in a mature field with depleted reserves. Enhanced and optimized cement slurry was engineered with a well-work approach that specified acoustic fluid-level monitoring. The packer leak was repaired successfully.

Introduction

This oil and gas field is 260 km from Kerteh, Malaysia. Discovered in 1971, first oil production was in 1978. The field is in the southeastern part of the Malay basin at an average water depth of 70 m. The field contains both gas and oil reservoirs. In August 2002, communication was observed between the production casing and tubing of the subject well, indicating a leaking production packer. Four major attempts to correct the problem were conducted, all unsuccessful. The first attempt was in February 2003 by bullheading calcium carbonate (CaCO3) into the annulus. This procedure was attempted again in May 2003. In August 2007, a coiled-tubing (CT) unit was used to spot cement inside the production tubing and displace it into the annulus through a gas lift mandrel to the top of the packer. Another cementing job was attempted in December 2008, through the same gas lift mandrel.

Diagnosis

Lessons learned from the first cementing failure, in 2007, were used to design the attempt in 2008. Even though job execution was smooth in the field, several mistakes occurred that were not realized by the team during the job-design process. The experiences of those cementing attempts helped mature the subsequent design and decisions, ensuring success for future packer-cementing jobs in peninsular Malaysia operations.

Cement-Slurry Design. CT-cementing procedures are different from those of conventional/primary cementing from a rig, with the biggest difference being the need for batch mixing for CT cementing vs. on-the-fly mixing for primary cementing. Batch mixing requires higher mixing energy compared with primary cementing, with an additional mixing energy to pump the cement slurry through the CT relative to pumping down the casing. The higher mixing energy decreases thickening time (TT) such that the cement slurry has potential to accidentally set inside the CT, thereby requiring a suitable retarder to prolong the TT.
En Route: The Production Capacity Challenge
Authors: Labastie Alain
Published: February 2015

President's column

Peak Oil Theory has been a subject of intense discussion since it was established by M. King Hubbert in the 1950s. The theory basically states that production is limited by resources—i.e., geology. I believe that, although it will be a reality one day, the theory is not correct globally for the short and mid term. But I also believe that we are in fact facing another limitation, one caused by production capacity.

For conventional hydrocarbons, explorationists have literally invented new domains for seeking oil and gas, and this has proven to be very efficient. A good example is the deepwater domain (now subsalt), which has added a large amount of reserves in various parts of the world and will certainly continue to do so for a while. The Hubbert decline curve, which historically has been a good fit with the production of the US Lower 48 states, is no longer applicable because of this domain extension; it works for a given domain.

We have produced most of the conventional hydrocarbons—these have been easy to produce, but in relatively small volumes. As illustrated by the resource triangle (Fig. 1), a concept invented by Steve Holditch, there are huge resources in unconventional hydrocarbons in both oil and gas but they are difficult to produce. Interestingly, the production from these resources is also difficult to predict. Look at the booming activity and production of shale gas in North America, for example; very few forecasts, if any, were anticipating that boom 10 years ago or even less. The resources are abundant.

The challenge we face comes from production capacity. I will illustrate what I am talking about with oil, but the situation is similar for gas. On one side, we will have a slight increase in demand—1% to 1.5% per year, according to the International Energy Agency’s “reference scenario.” On the other side, our producing fields are ageing, and will decline at a rate of about 5% per year. As a consequence, the gap between demand and production from existing fields will widen, to be filled by new production. These figures illustrate this challenge:

2009 production was about 85 million BOPD.

2019 demand will be about 95 million BOPD.

Taking into account the decline of existing fields, to go from 85 to 95 million BPOD we must add not 10 million BOPD production capacity, but about 45 million BOPD of new production. That represents half of today’s production.

This is an enormous challenge—the production capacity challenge. Huge efforts will be needed. To be successful will require technology, innovation, capital, and staff.
Technology Focus: Production/Facilities (December 2010)
Authors: Skeels Brian
Published: February 2015

Technology Focus

This year’s technical papers discuss employing advances gained in computational fluid dynamics (CFD) to induce multiphase-fluid separation through novel piping configurations and rotational dynamics rather than internal mechanical processes and baffles. These novel flow-chamber designs are reducing facility footprints and tank sizes, lending themselves to reduced platform-deck sizes offshore and extending water-depth ratings subsea. CFD also is improving the strategic placement of insulation barriers, piping geometry, and mixing of treatment chemicals to improve flow assurance and minimize erosion. Other techniques use biotechnology to detect and treat harmful microbial action at previously undetectable levels so that corrosion or increasing sour-service conditions can be avoided long before the number of microbes can grow to harmful levels. These papers demonstrate the oil industry’s continued vigor despite uncertain economic and regulatory times.

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

SPE 136292 • “Engineering Approaches—Progress in Calculation of Inhomogeneous Turbulence in Pipelines” by S.N. Kharlamov, National Research Tomsk Polytechnic University, et al.

SPE 136390 • “In-Line Technology—New Solutions for Gas/Liquid Separation” by E. Kremleva, SPE, FMC Technologies, et al.

IPTC 13121 • “Prediction of Optimum Thermal-Insulation Thickness for Oil and Gas Process Piping and Equipment Using a Simple Method” by A. Bahadori, Curtin University of Technology, et al.

SPE 130744 • “Rapid Determination of MIC in Oil-Production Facilities With a DNA-Based Diagnostic Kit” by Torben Lund Skovhus, Danish Technological Institute, et al.

SPE 126318 • “Ecological Advantages of Carbon-Enhanced MBRs Treating Oily Wastewater” by William G. Conner, Saudi Aramco.
Technology Focus: Bit Technology and Bottomhole Assemblies (December 2010)
Authors: Mensa-Wilmot Graham
Published: February 2015

Technology Focus

Performance Drilling—System Approach Will Yield Sustainable Improvements

The industry continues to develop new tools, technologies, and processes to help drive down drilling costs. This commitment to improve drilling efficiency and reliability, through effective questioning of relevant data, also has strong positive effects on drilling operations. Strides have been made, but there is more to be done.

In most instances, efforts to understand and develop sustainable-improvement strategies tend to isolate and focus on specific components [e.g., drill bit, drilling fluid, bottomhole assembly (BHA), and drive system]. In relating to these components, we usually are guided by past experiences and “rules of thumb.” Without a doubt, it is clear that the effect and value of our experiences are immeasurable. However, we need to shape our data-questioning processes around our experiences to challenge the rules of thumb. We have tools that will speed up this process.

First, we need a system approach to performance drilling. Extensive research has contributed to the development of high-performance positive-displacement motors and turbines. In addition, development of rotary-steerable tools has been extended successfully into slimhole applications. Earlier limitations of these tools, in terms of torque vs. revolutions-per-minute relationship, as well as product reliability, have seen tremendous improvements. What usually is missing is the selection analysis from a drilling-system perspective rather than as an individual component.

BHA design and modeling, a critical part of the system approach, must be practical and field driven. Negative effects of vibrations, with regard to downhole-tool life, borehole quality, and overall drilling performance, have been clearly established. As a means to vibrations mitigation, sources and specific modes must be identified. BHA design, as part of the system approach, must be cognizant of the drilling system’s functional requirements. In addition, performance-improvement discussions must focus on practical aspects of the application. System-based solutions will ensure consistent and sustainable improvements.

We have the key, let’s open the door.

Bit Technology and Bottomhole Assemblies additional reading available at OnePetro: www.onepetro.org

SPE 128767 • “Decoupling Stick/Slip and Whirl To Achieve Breakthrough in Drilling Performance” by Sean Xianping Wu, Smith Technologies, et al.

SPE 128211 • “High-Frequency Downhole Dynamic Measurements Provide Greater Understanding of Drilling Vibration in Performance-Motor Assemblies” by Andrew D. Craig, SPE, NOV, et al.

SPE 134488 • “Downhole-Vibration Measurement, Monitoring, and Modeling Reveal Stick/Slip as a Primary Cause of PDC-Bit Damage in Today’s Applications” by L.W. Ledgerwood III, SPE, Baker Hughes, et al.
Can Geoscientists Resolve the CCS Paradox?
Authors: Torp Tore A.
Published: February 2015

R&D Grand Challenges - This is the fourth in a series of articles on the great challenges facing the oil and gas industry as outlined by the SPE Research and Development (R&D) Committee. The R&D challenges comprise broad upstream business needs: increasing recovery factors, in-situ molecular manipulation, carbon capture and sequestration, produced water management, higher resolution subsurface imaging of hydrocarbons, and the environment. The articles in this series examine each of these challenges in depth. The R&D Grand Challenges Series, comprising articles published in JPT during 2011 and 2012, is available as a collection on OnePetro (SPE-163061-JPT).

International energy and climate organizations have found carbon capture and storage (CCS) to be a promising technology to resolve the squeeze between fast-growing global energy needs and global warming. Even environmental organizations say that making our energy use more efficient and building enough new renewable energy capacity takes too long. We need to get the CCS working to curb the growing greenhouse gas emissions if too large a climate change is to be avoided.

CCS consists of three major interdependent steps:

Capture the carbon, CO2 out of flue gases, either from the stack of a power plant or the blast furnace top gas in iron making.

Transport it by pipeline or ship it underground.

Safely keep it in a storage site for thousands of years.

The technology for each of these steps has been used for decades in the industry, mostly in oil and gas. The important change is the scale—from about 100,000 to 1 million metric tons per year in the past. Today, we see the need for handling 10 million tons in each installation and for perhaps several thousand installations. The amount of CO2 produced from one power station varies from 2 million to 10 million tons; a modern iron-making blast furnace emits up to 10 million tons per year. The costs of the technologies for a large-scale CO2 handling chain are estimated to be split roughly 75%-10%-15% for capture-transport-storage.
West of Shetland Development Gathers Momentum
Authors: Sheehan John
Published: February 2015

BP is ramping up its West of Shetland operations with the UK government approval to push ahead with the second phase of its giant Clair field development, Clair Ridge. Plans to redevelop the Schiehallion and Loyal fields with a new floating production, storage, and offloading vessel (FPSO) are also gathering pace.

The Clair reservoir is the largest known hydrocarbon resource on the UK Continental Shelf (UKCS), occupying an area of 220 sq km. It is located approximately 75 km west of the Shetland Isles in 459 ft of water. Because of its size and complexity, it is being developed in phases.

Clair Ridge, in UKCS Block 206/8, lies to the northeast of Clair Phase 1 and will be tapped with a pair of bridge-linked platforms—a drilling and production (DP) facilities platform and an accommodation and utilities (QU) platform. The new platforms have a 40-year design life and will require a total capital investment of about GBP 4.5 billion (USD 7.16 billion).

The topsides for the two platforms are being built in modular form by Hyundai Heavy Industries in South Korea and will be transported to the Clair Ridge field on five Dockwise heavylift vessels. Kvaerner Verdal in Norway is building the platform jackets. The DP jacket will have a total weight of 22,300 tonnes and the QU jacket will weigh 9,000 tonnes.

Peter Brawley, the Clair Ridge hook-up and export systems manager, said the sheer scale of the project is a challenge in itself. “This is a huge platform we are building. The biggest platform we operate on the UKCS at the moment is Magnus at 34,000 tonnes and here, we have topsides of 40,000 tonnes. It is bigger than anything we have built in the UKCS, so the scale is a challenge,” he said.

“On the QU platform we have one large 10,000 tonne module, which comprises the bulk of it. On top, we have a power generation module and on the side, we have the accommodation module. We will have three lifts on QU.

“On DP, we have the DP East module, the DP West module, each of which is around 10,000 tonnes. Then we have the compression module that goes on top of DP East and then we have the drilling support module and the drill rig itself. The final two modules are the flare boom and the bridge,” he said.

The facilities will have a maximum processing capacity of 120,000 BOPD, which will flow to the Clair Phase 1 pipeline through a new oil export pipeline and onward to the Sullom Voe Terminal. The DP platform will also be tied into the West of Shetland Pipeline System through a carbon steel gas export pipeline.