bluuebunny/crossref_metadata_2025 huggingface dataset:
Malaysia's Prime Minister Opens Inaugural OTC Asia
Authors: Donnelly John , Rassenfoss Stephen , Henni Abdelghani
Published: February 2015

Conference review

The first Offshore Technology Conference Asia exceeded attendance expectations while providing in-depth panel and technical sessions on the increasingly important Asian energy sector as well as other globally significant upstream trends and technology applications. The conference was held from 25 to 28 March in Kuala Lumpur.

Malaysia’s prime minister, the Hon. Dato’ Sri Mohd Najib Tun Haji Abdul Razak, cited the importance of the Asia Pacific region in future global energy activity during his keynote address at the official opening of the first OTC Asia. He was joined at the opening ceremony by YBhg Tan Sri Dato’ Shamsul Azhar Abbas, chairman of the OTC Asia Advisory Committee and group chief executive officer (CEO) of Petronas, and Edward Stokes of Chevron, chairman of the OTC Board of Directors.

“These are exciting times for the Asian oil and gas industry, and that is why it is apt that the first OTC Asia is being held in Malaysia,” he said.

“Asia is a continent with a voracious appetite for energy,” he said, noting the region’s projected 2.5% annual growth in consumption and the fact that Asia will account for more than 60% of total global energy demand in 2030.

The region’s rising consumption is not being met as local hydrocarbon supplies are in decline and some countries that once were exporters of energy are now importers. “The easy oil is indeed gone,” presenting challenges, but also opportunities, for the oil and gas industry, the prime minister said.

“We are embarking on a new era of innovation” to help unlock new resources in hard-to-reach places, he said. “We are going further and deeper both literally and with the technology we use.”

Malaysia has “the perfect mix of ingredients to be a regional energy hub,” the prime minister said, because of its location, resources, technical capability, world-class infrastructure, and legislative framework, which is business friendly. He noted the success of risk-service contracts that were introduced in 2011 and the growth during the past 2 years in Malaysian domestic hydrocarbons output. “This success is no accident,” he added.
Overview: Coiled-Tubing Applications (June 2004)
Authors: Rike E.A.
Published: February 2015

Overview - No abstract available.
Coiled-Tubing-Drilling Re-entry: Case History From East Kalimantan
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 89632, "Coiled-Tubing- Drilling Re-entry: Case History From East Kalimantan," by H.J. Wright, SPE, BP; B. Aristianto and R.G. Gan, SPE, VICO Indonesia; and J.R. Jenie and H.A. Kyaw, SPE, Schlumberger, prepared for the 2004 SPE/ICoTA Coiled Tubing Conference and Exhibition, Houston, 23-24 March.
New Insight Into Heat Management in the Coalinga Field
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 86984, "Heat Management in Coalinga - New Insight to Manage Heat in an Old Field," by A. Zahedi, SPE, R. Johnson, SPE, and C. Rueda, SPE, ChevronTexaco, prepared for the 2004 SPE International Thermal Operations and Heavy Oil Symposium and Western Regional Meeting, Bakersfield, California, 16-18 March.
Dialog (June 2004)
Authors: Graham Seldon B. , Turrentine Robert E. , Duhon Howard
Published: February 2015

Dialog - Discussion/Reply. No abstract available.
Q&A with Peter Seifert
Authors: Seifert Peter , Donnelly John
Published: February 2015

The theme of the upcoming EAGE/Europec conference is "Opportunities in Mature Areas." Why was this chosen as the main topic?

The increasing demand for oil and gas has created the need to expand exploration into remote areas such as deepwater offshore, the Arctic/permafrost, or in deep targets at 5000 to 6000 m depth. The risks and the costs are high for exploration and developments in those remote areas. Therefore, it is of great interest to the oil industry to find and produce additional hydrocarbons from mature areas, especially at the current oil-price scenario.

What is your assessment of how quickly the industry is developing and using leading-edge technology that could increase output from mature fields?

The development of advanced technology in our industry is of course dependent on oil prices. During periods of high oil prices like today, we clearly see a technology jump forward. This will lead in the short term to increased output from mature fields.

How good a job does the oil and gas industry do in getting new technology to market? Are comparisons to industries that introduce technology faster—the medical and computer fields, for instance—fair?

We cannot compare the oil industry with the computer industry, and there is no need to anyway. Our industry is ready any time to apply new technology, but it is very careful about checking the related costs vs. the potential results. New technology is brought to the market rather quickly if there is good demand for it. For example, with 4D seismic and multilateral drilling, the whole industry jumped on it. Again, this is much related to oil price levels.

What are the main technology needs on the E&P side?

The industry should continue to mature the existing technologies for enhanced-oil-recovery methods for old fields. Quick access to additional producible reserves is most interesting to oil companies. For deepwater developments, the issue is getting the costs down for subsea completions; floating production, storage, and offshore loading; and transmission systems. This would open up new opportunities to develop resources economically, which are out of reach today.

What is OMV's current oil and gas production, and where is the company most active in E&P?

OMV, including Petrom, currently produces 338,000 BOE/D. We are active in E&P in 16 countries on five continents. We have defined five core areas for our E&P activities: the Danube region from Austria to the Black Sea, North Sea/West of Shetlands, north Africa, the Middle East, and Australia/New Zealand. In addition, we have begun to target Russia as a sixth core area. We are trying to acquire assets there. Our main interest in Russia is to acquire an oilfield development project first, and then exploration assets will follow.
Coiled-Tubing Operations in the Panna Field Offshore Western India
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 100149, "Operability Challenges During Coiled-Tubing (CT) Well Intervention: Panna Field Case Histories From Western India Offshore," by S. Kale, SPE, and R. Proctor, SPE, BJ Services Co., and S. Paliwal, SPE, and S. Nayak, SPE, BG E&P India Ltd., prepared for the 2006 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 4-5 April.

Coiled tubing (CT) was used in well interventions offshore western India. Well completions are open hole, open hole with tail pipe, and cased hole with swell packers. CT entry was essential to operate sliding sleeves installed in the completions. The full-length paper documents case studies and reviews attempted solutions such as bottomhole-assembly (BHA) excitation tools and contact-friction reducers to extend reach and increase downhole force.

Introduction

Located off the west coast of India, the target reservoir in the Panna field is a limestone layer. Horizontal wells have been drilled and completed in the field since 1997. The main difference between the wells completed in the late 1990s and current wells is the horizontal-section length.

Challenges associated with CT operations can be considered as logistical and technical. The main logistical challenges include limited crane capacity and deck space for CT rig up. Technical challenges include limited CT downhole force. Because of logistical challenges, the preferred CT size cannot be used on most platforms.

Logistical Challenges

Panna field has two types of platforms, one with nine slots and the other with 15 slots. The nine-slot platforms have limited deck space and crane capacity. Larger CT sizes such as 1 3/4-in.-outside-diameter (OD) pipe cannot be rigged up on nine- slot platforms but can be used on the 15-slot platforms.

Two memory-production-logging (PL) campaigns were undertaken on the 15-slot platforms. Because of limited deck space on some platforms, fluid-pumping and nitrogen equipment, tanks, and mixing equipment were offloaded to a dedicated supply boat as required. This presented the logistical challenge of timing the operations to boat availability and tide conditions.

Technical Challenges

The two most important technical challenges faced by the team were CT-reach prediction and identification of possible solutions to meet well-intervention objectives. The objectives of well interventions in late-1990s completions were acid stimulation and memory PL. Current completions require sliding-sleeve manipulation, acid stimulation, and PL.

Accurate CT-entry predictions require use of a CT simulator. In addition, the engineer using the simulator must have a thorough understanding of the modeling parameters and analysis process.
Technology Focus: Coiled Tubing Applications (June 2008)
Authors: Misselbrook John
Published: February 2015

Technology Focus

Viewed from the wide perspective of the exploration and production industry, the coiled-tubing (CT) fraternity might be regarded as a relatively small group of fringe players who plastically deform pipe for a living. However, the truth is that CT has grown into a business generating USD 3 billion in revenue and has become an indispensable tool in many operating locations.

Like many emerging technologies, the first decade of CT's existence was mostly a struggle to stay alive; but having survived the challenges of the early years where pipe failure was a regular occurrence (Who doesn't remember a CT string inexplicably parting in a well and the subsequent fishing operation?), the industry changed gears and began to expand outside niche areas. In more than 3 decades of continuous development, we have seen CT materials reach an unprecedented level of manufacturing reliability such that premature pinholes have been virtually eliminated. As a result, pipe sizes have increased and strings have become longer, which in turn has propelled the technology in ever-increasing directions. Thirty years ago, a typical string weighed approximately 12,000 lbm, while today we routinely use strings weighing in excess of 60,000 lbm, with some of the larger strings tipping the scales at 120,000 lbm or more.

The technology has evolved from its traditional role of gas lifting and sand cleanouts to embrace such diverse applications as re-entry directional drilling, CT fracturing, multilateral stimulation, and grass-roots drilling to name just a few. The papers selected for this feature are designed to highlight just how far the technology has come and hopefully stimulate the reader along some new avenue of investigation.

Interestingly, many of the early adopters of this technology are still active in the field, having dedicated much of their working lives to both the advancement of the technology and the exploitation of such technology in new applications. I never cease to be amazed at their ingenuity, and I am confident that the next generation will continue the legacy of the pioneers.

Coiled Tubing Applications additional reading available at the SPE eLibrary: www.spe.org

SPE 110382 • "Case History: Application of Coiled-Tubing Tractor to Acid Stimulate Openhole Extended-Reach Power-Water-Injector Well" by Ayedh M. Al Shehri, SPE, Saudi Aramco, et al.

SPE 106639 • "16Cr Coiled-Tubing Field Trial at Prudhoe Bay, Alaska" by J.Y. Julian, SPE, BP plc, et al.
Technology Focus: Deepwater Exploration and Production (June 2009)
Authors: Olson Karen
Published: February 2015

Technology Focus

Even in today's changing times, the challenges of deep water continue to demand new and innovative technologies. Explorers are finding new fields hidden tens of thousands of feet below the mudline, reaching depths that cannot be completed currently. To produce from these depths, companies are developing completion equipment rated to high pressures both in absolute and in differential terms. Successful qualification of new high-yield metal alloys is a key enabler for delivery of high-pressure/high-temperature completion-equipment solutions; specifically in the development of a 20,000-psi-rated surface-controlled subsurface safety valve, 15,000-psi-differential-rated completion equipment, and 30,000-psi-rated downhole-test-tool equipment. The current mechanical-property limits for high-yield metal-alloy materials must be extended with material solutions that provide robust corrosion performance.

Past experiences by many operators have led to a rigorous assurance process to ensure that new equipment will work and work the first time. Equipment statement of requirements, detailed design reviews along with comprehensive qualification plans, system-integration tests, and, potentially, field trials are part of the overall equipment-integrity assurance.

As we continue to explore in deep water, new horizons at depths never before completed demand new ideas and new technologies to enable development. As professionals working in the oil industry, we need to continue working together to find new ways to develop these deeper high-pressure reservoirs and then to develop the equipment to produce them. We need to keep that "can-do" attitude.

Deepwater Exploration and Production additional reading available at the SPE eLibrary: www.spe.org

SPE 113727 • "Optimizing Wireline-Gun-System Design and Perforating Performance for Very Late Changes in a Gulf of Mexico HP/HT Deepwater Well" by L. Sabbagh, SPE, Schlumberger, et al.

Additional reading available at OnePetro: www.onepetro.org

OTC 20022 • "Geohazard Assessment in a Deepwater Subsea Development—A Contractor's Perspective" by Roberto Bruschi, Saipem Energy Services, et al.

OTC 20087 • "Early Testing—Jabuti Extended Well Test" by J.R.C. Melo, Petrobras, et al.
Performance Improvement of Viscoelastic Stimulation Fluids With Nanoparticles
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 113533, "Performance Enhancements of Viscoelastic- Surfactant Stimulation Fluids With Nanoparticles," by James B. Crews, SPE, and Tianping Huang, SPE, Baker Hughes, originally prepared for the 2008 SPE Europec/EAGE Conference and Exhibition, Rome, 9-12 June. The paper has not been peer reviewed.

The full-length paper introduces newly developed, select nanosized crystals with unique surface charges and explains how nanoparticle technology pseudocrosslinks viscoelastic surfactant (VES) rod-like micelles together to improve the fluid-loss control and proppant transport of VES fluids to a performance level similar to that of a crosslinked-polymer fluid (CPF). The nanoparticle-pseudocrosslinked VES-micelle fluid develops a wall-building pseudofilter cake on the face of porous media to control fluid loss.

Introduction

CPFs are the most common type of fluid used for hydraulic fracturing. These fluids can achieve high viscosities with low leakoff rates for a wide range of reservoir temperatures and permeabilities. With their efficient leakoff control, CPFs can be used to generate excellent fracture geometry in most reservoirs. They also have excellent proppant-suspension and -placement capability. However, one weakness of CPFs is the fracture-conductivity dam-age that occurs as a result of incomplete crosslinked-polymer filter-cake removal from the fracture.

Over the past decade, classical VES-fluid systems have been used for frac packs and conventional hydraulic fracturing. The composition of these fluid systems typically has been fresh water, salt [such as 4% potassium chloride (KCl)], and VES product. The classical VES-fluid systems have viscosity-dependant leakoff control into porous media and do not develop or leave filter cake on a fracture face. The advantage of this type of leakoff control is that no filter-cake damage occurs in the fracture. However, a disadvantage is that a significantly high amount of whole-gel leakoff occurs into the formation during a treatment, and most often insufficient treatment fluid remains in the fracture for generating proper fracture geometry. Additionally, no internal breaker technology has existed for VES systems until recently. The reliance on the external breaking mechanism has resulted in too frequent poor and incomplete VES-fluid cleanup from the treated reservoir.

Crosslinked Polymer vs. Pseudocrosslinked Micelles

Two key parameters for crosslinking polymers in an aqueous medium is the molecular weight of the polymer and the degree of polymer overlap. The more polymer overlap there is, the more intrapolymer (polymer-to-polymer) crosslinking that can occur. In almost all cases, crosslinking polymers significantly improves performance properties for hydraulic fracturing, such as much higher fluid viscosity, improved thermal stability, better proppant transport, and lower rate of fluid leakoff.
Enhancing Well Safety and Economics
Authors: Gala Deepak M. , Menard Bill , Nas Steve , Offner Mike
Published: February 2015

Technology Update

As the “low-hanging fruit” of the world’s oil and gas accumulations are more fully harvested, so the industry has been forced into tackling more complex and challenging projects such as ultradeep prospects, deepwater applications, and high-pressure/high-temperature (HPHT) wells to continue fulfilling the world’s appetite for fossil energy. This has led to more widespread use of nonconventional techniques such as drilling with casing, coiled-tubing drilling, underbalanced drilling (UBD), and managed-pressure drilling (MPD), including pressurized-mud-cap drilling (PMCD), with their attendant well-control and safety challenges. Among these challenges are

Moderate to severe lost circulation

Formation damage as a result of having to kill the well before tripping pipe

Pore-pressure and fracture-gradient similarity, leading to kick/loss cycles and well-control problems

Use of snubbing techniques to trip the pipe in and out of the hole above the “pipe-light” depth, with the associated added cost and risk.

Overall operational safety

Operational economics

As a result, mitigating drilling hazards and reducing operational non-productive time (NPT) has become an extremely important facet of well operations.

Downhole-Isolation-Valve System

The need to address these challenges led to development of the Downhole Deployment Valve in the year 2000. This is an isolation-valve system consisting of a deep-set flapper valve that is run as an integral part of the intermediate casing string and set at a predetermined depth below the pipe-light depth, or deeper as operational requirements dictate, with a full-opening inside diameter equivalent to that of the casing. It is not a safety valve in the accepted sense of the word, in that it is not a fail-safe device, but rather is powered open and closed by the application of hydraulic pressure at the surface to one of two encapsulated control lines attached to the casing outside diameter (OD). The downhole isolation valve (DIV) can be run in two separate configurations, depending on operational requirements (Fig. 1).
Coiled Tubing Used To Fish Coiled Tubing From a Live Gas/Condensate Well
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 129507, ’Fishing Coiled Tubing From a Live Gas- Condensate Well With Coiled Tubing While Under Production,’ by B.I. Kang, B.S. Murugappan, SPE, O.K. Kwon, and G.J. Sinn, Korea National Oil; I. Foster and L. Robinson, Weatherford; and J.B. Elliot, SPE, R. Hampson, and B.L. McKinnon, Halliburton, originally prepared for the 2010 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 23-24 March.

This case study examines the techniques required to recover a coiled-tubing (CT) fish from a live gas/condensate well by use of CT. These procedures recently were implemented offshore Vietnam, where an extremely fluid-sensitive formation prevented killing the well because the formation likely would not have recovered. Using the techniques described in the full-length paper, a 1.50-in., 9,177-ft-long CT fish was recovered from a well while keeping the well on production. 

Introduction

CT is used around the world as a common well-intervention technique, and its scope of usefulness extends into many areas, including CT drilling, logging, fishing, milling, debris cleanout, and gas lifting. As technology progresses, so does the usefulness of CT to the industry as a whole, and the physical boundaries of what CT can achieve are being pushed constantly. This can lead to an unplanned failure of the string while in the well.

When a CT string parts in hole, the resulting fishing operation can be dangerous and complex; as such, standard practice dictates that the well be killed as a first step to recovering the parted string. However, killing the well can introduce pressures and foreign fluids to any open formations, which can lead to permanent or long-lasting negative effects on well performance.

Background

While using CT for logging the production of a well offshore Vietnam, an uncontrolled gas breach at surface required a complete emergency shut-in of the well, and as a result, 9,177 ft of 1.50-in. CT was sheared at the blowout preventer (BOP) and dropped 5,489 ft to total depth. The deviation of the well varied between 30 to 57°.

At first, it was feared the fish might have buckled catastrophically after impacting the bottom of the well, in which case recovery would be nearly impossible. However, the top of the fish was later found to be at 5,538 ft from surface (just 49 ft below the expected depth of 5,489 ft); there-fore, only slight damage was expected to the bottom of the fish.

As is the usual first step to retrieve a difficult fish, it was proposed that the well be killed. However, the client company refused, stating that the extremely fluid-sensitive formation would likely not recover from any fluid damage and thus that killing the well would result in the loss of the well itself.
Comments: State of the Gulf
Authors: Donnelly John
Published: February 2015

Editor's column

The mood at last month’s Offshore Technology Conference in Houston was decidedly upbeat compared with 2010, when the Deepwater Horizon accident had taken place in the US Gulf of Mexico only days before the conference. But the explosion and its consequences dominated discussion at this year’s conference, from improvements in blowout preventers to panel discussions involving company and government officials. One certainty arising from the accident appears to be more government oversight of the oil and gas industry.

Michael Bromwich, director of the US Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE), announced that regulators will have authority over contractors involved in deepwater leases in addition to operators. “I am convinced that we can fully preserve the principle of holding operators fully responsible, and in most cases solely responsible, without sacrificing the ability to pursue regulatory actions against contractors for serious violations of agency rules and regulations,” he said.

The BOEMRE’s report on the accident will be released before the 27 July deadline, Bromwich said. That report will examine all aspects of the disaster, including the steps that operators and contractors took leading up to and after the accident as well as the effectiveness of the blowout preventer. It is still too early to say what new regulations governing blowout preventers might be forthcoming, he added. After the conference, Bromwich toured several industry remote monitoring centers to observe their operation up close. Many conference attendees said they were braced for a new climate in the Gulf, one that may include even more new regulations than have been implemented in the past year.  

The Gulf will be slow to recover from the disaster, according to one new industry report. The study by consultancy Wood Mackenzie said that Gulf production fell 80,000 BOED in 2010 and will decline another 375,000 BOED this year because of the moratorium issued by the US government after the accident. Exploration drilling then will strengthen in 2012 and return to healthy activity in 2013. New projects will eventually allow Gulf production to rise beyond pre-accident levels in 2016, according to the report.

Last month, the US government approved Shell’s plan to drill in several deep-water locations in the Gulf. It was only the second deepwater plan approved by the government since the lifting of the deepwater drilling moratorium in October, both involving Shell discoveries. The Shell Appomattox field plan includes drilling eight wells in 7,200 ft. of water approximately 70 miles off the Louisiana coast. In the past year, the US government has approved plans for the drilling of 58 new offshore wells in the Gulf.
Drillable Mud Motor System Brings Step Change for Running Tubulars
Authors: Davis Lance , Al-Othman Abdulaziz
Published: February 2015

Technology Update

Oil and gas well construction requires the installation of tubulars at a specific depth, prescribed for reasons of mechanics, formation pressure and wellbore integrity, or accessing reserves. Deepwater construction has an additional need to land all strings in the subsea wellhead with precision. The industry recognizes this as a most significant operation. There have many instances of failed well programs where critical depths have not been secured. A step change technology for this purpose has been created to reduce well construction risk, applicable to all casing strings, liners, and completion strings.

Introduction: Solving an Important Industry Problem

Adverse wellbore conditions, instability, irregularity, doglegs, and fill, among other factors, often result in inefficient, incomplete casing running operations in terms of nonproductive time and potentially lost production. If the rig is equipped to do so, it may be possible to overcome such problems by reaming. However, as casing strings get longer and heavier, and for rigs without a top drive or where other factors lead to a limited ability to rotate the casing, there has been little option but to accept that casing placement problems are just a “cost of doing business.”

The industry problem is clear, but there do not appear to be key performance indicators on the percentage of casings run to 100% of target depth. Well construction creates well integrity, ensured in part by following the plan, landing casing on depth, and obtaining a well cemented tubular. Cost of failure to run the casing to design depth can reflect many factors, including the costs of drilling unused hole; running, pulling, and rerunning casing; and any subsequent casing plan revision. There is also the potential cost to reputation for failing to deliver to plan.

In developing a new technology to address the problem, it is of primary importance to add no risk to the existing well control or casing running process. Ideally, for reasons of safety, operation of new equipment should not require additional personnel.
Q&A with Norman Gilsdorf, President, High Growth Regions for Russia, Central Asia, and Middle East, Honeywell International
Authors: Gilsdorf Norman
Published: February 2015

Q&A

You were appointed to your new position last year. Can you tell us about your new role?

Honeywell recently made the decision to place more focus and emphasis on the Russian, Central Asia, and Middle Eastern markets. In order to do this, we wanted to employ a similar strategy to what we did in China 6 years ago—putting in place a leader who would be able to integrate all of our businesses and help with positioning Honey well with customers and partners in these markets.

What are Honeywell’s recent offerings for the oil and gas industry? Honeywell and its various subsidiaries offer a variety of products and solutions. UOP, a Honeywell subsidiary, recently acquired the US company Thomas Russell. This acquisition allows us to offer solutions to enable companies to deploy modular-packaged equipment units to remove gas contaminants and capture higher valued natural gas liquids such as liquefied petroleum gas (LPG). This is very interesting technology for stranded gas or gas that is in dispersed reservoirs such as shale gas and shale oil, which can be challenging to monetize otherwise. UOP also recently launched a new heavy oil technology for upgrading residue and the UOP methanol-to-olefins technology is seeing a lot of demand in areas with methane, particularly in places such as China. Overall, UOP continues to have technologies for gas processing, including membranes to remove CO2 and other contaminants.

On the automation advancement side, process solution developers such as Honeywell Process Solutions, in collaboration with oil companies, have made significant efforts to develop oil fields of the future, or smart fields. This will allow companies to be able to gather data from different wells and resources, allowing for more efficient management. For example, our software platform sits above the plant level and connects the plant through the enterprise resource planning system, allowing for safer operations and lower costs. It can also help the operator work smarter and more effectively.

Do you think that the recent shale revolution in the US will affect the Middle East?

I think it has already had an effect in the Middle East through its impact on the US market. Five years ago, several major US downstream players were in the process of backing down on production facilities in the US and were considering joint ventures and partnerships to build facilities in the Middle East or China. What is happening as a result of the shift toward shale is that several of these players have revived their operations the US, not just restarting their facilities, but also building new facilities.
Technology Focus: Coiled Tubing Applications (June 2013)
Authors: Misselbrook John
Published: February 2015

Technology Focus

In the two previous JPT coiled-tubing features, I commented on the remarkable growth the coiled-tubing industry has seen in North America, resulting largely from the shale revolution. This growth attracted numerous new players into the industry, in addition to the capacity additions made by the existing service providers. Regrettably, such unrestrained growth is rarely accompanied by a matching level of service quality. This concern about performance prompted the selection of the first paper in this feature. Although this is just one service provider’s history of stuck pipe, it likely mirrors the performance of the industry at large and serves as a reminder to all operators of the risks inherent in being too rigorous in adopting a cookie-cutter approach to certain coiled-tubing operations. The authors are to be commended for their frank reporting of the issues.

In fact, the gallop toward ever-larger coiled-tubing strings has not been mirrored by increasing the size of the reels on which they are spooled. The result is that, in addition to increasing the hoop stress resulting from ever-increasing injection pressures, coiled tubing is being subjected to levels of strain that have not been encountered previously. This places strenuous demands on the bias welds in the strings and requires more-rigorous attention to string-fatigue management. This continues to be a focus of the industry, as does the slightly greater susceptibility of bias welds to pitting corrosion from recirculated formation water of varying origins.

While I am still on the subject of large-diameter coiled tubing, the second paper focuses on another aspect of the industry and highlights the level of engineering detail required of many coiled-tubing activities and is especially typical of large multiwell offshore projects. It serves as an example of the level of planning and professionalism required for multidisciplinary operations but also reminds us that many superficially basic well-intervention operations are never as simple as they might appear.

Finally, I could not resist a paper of a more theoretical nature because it addresses an activity of increasing importance to the industry—namely, extended reach—which, in turn, is the primary driver behind the use of larger sizes of coiled tubing. We need technology and the science behind it if we are ever going to come close to approaching the lateral reach available to the drillers.

Recommended additional reading at OnePetro: www.onepetro.org.

SPE 162797 New Coiled-Tubing-Deployed Multizone Stimulation Method Increases Reservoir Access by Tyson Dunlop, Halliburton, et al.

SPE 163910 Coiled-Tubing-Jet-Cutting Multiple-Stage Fracture Treating Improves Fracture-Treatment Techniques To Unlock Bypassed Reserves in Cotton Valley Sands, Dorcheat Macedonia Field, Magnolia, Arkansas by R.W. Pomrenke, Bonanza Creek Energy, et al.

SPE 163884 Development of a New Coiled-Tubing Life-Tracking Process by Kenneth R. Newman, KNewman Engineering
Comments: Capital Spending Declines
Authors: Donnelly John
Published: February 2015

Editor's column

Both international and national oil and gas companies are putting tighter reins on capital spending this year, which is not only affecting merger and acquisition activity but could also impact expensive deepwater projects and total global oil supply growth.

The industry often must maneuver between the long-term view of financing complex, costly projects and appeasing short-term shareholder demands. This year is no different. After hearing repeated complaints from the investment community on what it sees as lackluster performance amid historically high oil prices, several large firms cut back spending this year. Most notable to cut were the largest Western majors ExxonMobil, Chevron, Total, Shell, and BP, according to investment banker Morgan Stanley. These integrated majors are cutting capital spending by 10% this year compared with 2013 to a total of USD 33 billion, according to Energy Intelligence Research and Advisory. Morgan Stanley now predicts that global oil supply growth will rise to just under 6 million BOPD before falling to 4.7 million BOPD during 2016–18.
Carbon Capture: Harnessing Carbon Dioxide in the Middle East
Authors: Henni Abdelghani
Published: February 2015

Carbon Capture

The migration to ultra-mature production and concern about rising greenhouse gas emissions mean that the implementation of carbon capture and storage projects are coming into sharper focus than ever before in the Middle East.

Capturing carbon dioxide (CO2) and using it in enhanced oil recovery (EOR) is one strategy being widely adopted. Studies showing the region having one of the world’s highest per capita environmental footprints have led governments to look for ways to improve their rankings in greenhouse gas emissions.

So far, Oman is the only country in the region to have launched EOR programs on a large commercial, rather than pilot, scale in a bid to stem and reverse years of declining crude production. In Abu Dhabi, tertiary gas injection has been under way for decades at the Total-operated Abu Al Bukhoosh field with great success. As production in the region matures, more countries are expected to implement EOR programs.

The application of CO2 EOR provides two advantages for companies in the Middle East. It allows natural gas that would otherwise be used for injection into oil fields for secondary recovery to be freed up to meet domestic requirements, such as power generation and industrial use, or to limit the costly import of liquefied natural gas. Moreover, it helps limit emissions in the region.
Polymer-Flooding Pilot Finds Success in Previously Waterflooded Reservoir
Authors: Wilson Adam
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 166255, ’Polymer-Flooding-Pilot Learning Curve: 5+ Years' Experience To Reduce Cost Per Incremental Barrel of Oil,’ by J. Buciak, SPE, G. Fondevila Sancet, and L. Del Pozo, Grupo CAPSA, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed.

A successful pilot test of polymer flooding was conducted in the San Jorge Gulf basin, a mature waterflood with the presence of heterogeneous reservoirs and viscous oil under reservoir conditions. During the past 5 years, 3,200 tons of hydrolyzed polyacrylamide polymer was injected at concentrations of 1,500 ppm. The polymer flooding resulted in an increase in oil production to 100% and a decrease in water production to 50% in original central wells.

Introduction

The Diadema oil field is in the San Jorge Gulf basin in southern Argentina. The field has 480 producer wells and 270 injector wells. The reservoir being polymer flooded is characterized by high permeability (an average of 500 md), high heterogeneity (10–5,000 md), high porosity (30%), very stratified sandstone layers (4–12 m of net thickness) with poor lateral continuity (fluvial origin), and 20 °API oil (100 cp under reservoir conditions).
The Quadruple Bottom Line (July 2004)
Authors: Baker Kate H.
Published: February 2015

President's column - No abstract available.
Health, Safety, and Environment: Conference Encourages Industry to Step Up to HSE Challenge
Authors: Donnelly John
Published: February 2015

Conference review - No abstract available.
Phosphonic Acid for Stimulating HF-Sensitive Reservoirs
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 89415, "Phosphonic Acid Complex for Stimulating HFSensitive Reservoirs - A Revolutionary Response," by Linus Nwoke, SPE, and Chike Uchendu, SPE, BJ Services; James Arukhe, SPE, Shell; Philippe Essel and Felix Ndinemenu, Total; and Alessandra Vecchio and Sylvester Fatusin, SPE, NAOC, prepared for the 2004 SPE/DOE Fourteenth Symposium on Improved Oil Recovery, Tulsa, 17-21 April.
Overview: Multilateral/Extended Reach (July 2004)
Authors: Wolfson Larry
Published: February 2015

Overview - No abstract available.
Meeting the Zero-Discharge Challenge for Produced Water
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 86671, "Meeting the Zero- Discharge Challenge for Produced Water," by B.L. Knudsen, SPE, M. Hjelsvold, SPE, T.K. Frost, M.B.E. Svarstad, P.G. Grini, SPE, C.F. Willumsen, and H. Torvik, Statoil ASA, prepared for the 2004 SPE International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Calgary, 29-31 March.
Record ERD Well Drilled From a Floating Installation
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 98945, "World-Record ERD Well Drilled From a Floating Installation in the North Sea," by A. Hjelle, SPE, T.G. Teige, SPE, K. Rolfsen, K.J. Hanken, SPE, and S. Hernes, SPE, Statoil, and Y. Huelvan, Schlumberger, prepared for the 2006 IADC/SPE Drilling Conference, Miami, Florida, 21–23 February.

Well 34/8-A-6 AHT2 was drilled from the Visund field floating production and drilling unit (FPDU) in the North Sea with initial production in October 2005. The well was drilled to 9082 m measured depth (MD) and has an along-hole depth of 7593 m.

Introduction

The Visund oil/gas field is 150 km offshore the west coast of Norway in a water depth of 335 m. The field was discovered in 1986, with first production in 1999. The depth of the main reservoir is 2900 to 3000 m true vertical depth (TVD), with a maximum pore pressure of 434 bar. The field is 24 km long and 4 km wide. With this field shape, extended-reach-drilling (ERD) wells drilled both to the north and to the south will increase drainage area and thereby the total recovery from the field. The Visund FPDU is centrally located over the field. The Visund North satellites consist of two wells tied back to the FPDU with a 9-km-long subsea pipeline.

In the early preplanning phase, the subject well was planned as a separate subsea development, drilled by a separate semisubmersible rig. A new technical and economical study showed that this well could be drilled more economically from the existing Visund FPDU, through existing subsea systems. Fig. 1 shows the well profile.

Planning Phase

The planning phase of this well was performed by use of the continuous-improvements model (Fig. 2). The first plan recommended drilling for a separate subsea-development well. After gaining experience, it was decided that the well could be drilled from the Visund FPDU. The drilling plan was completed together with a separate risk document covering critical events that could be identified before drilling the well. This risk identification process was performed in a workshop together with the service companies and the drilling-contractor personnel working on the Visund field. The detailed rig procedures that were to be used on the rig floor also were prepared onshore in the same type of workshops. This proved to be a good way of building a committed team and identifying risks and parallel activities that could be prepared before the operation.

Peer assist and review were performed on this well to ensure that relevant experiences were included in the planning phase. After the well was completed, a final well meeting was held with the involved service companies ensuring that relevant experiences were recorded for the next well.
Q&A with Jacques Bosio
Authors: Bosio Jacques , Donnelly John
Published: February 2015

Editor's Note: In recognition of SPE's 50th anniversary this year, JPT is conducting interviews with several Society luminaries about their careers, their relationship with SPE, and the changes they have seen in the oil and gas industry and the Society over the past several decades.

In 1993, you became the first person outside of the United States to hold the office of SPE President. What was the significance of this and was its significance realized at the time?

SPE was perceived as 100% US at the time. But SPE was opening new sections every year outside the US already and appeared to be going in that direction. But, let us face it, I would say that one half of the SPE Board of Directors was not very much in favor of becoming totally international. Fortunately, some Presidents before me—such as Orville Gaither (1990) and Kenneth Robbins (1985)—had vision and realized that the central gravity of the oil business was moving east. Because of the North Sea, which was being developed, and of course, the Middle East, Texas was no longer the center of gravity. So it was really time to integrate the rest of the world into SPE, and it was also time to make it known that SPE had evolved and was truly becoming international.

So the idea of a non-US President would be a symbol and I think it worked. When our members opened up their JPT one month, they had proof that SPE was going international, since the least you can say about a Frenchman is that he is a true foreigner! It was a sign of a clear evolution.

Was there much reaction from the membership?

The reaction was positive. SPE had opened a new section in France in the 1980s and in other areas already. As I traveled around—to Norway, to Great Britain, and to other places—the members all said they found the idea of SPE becoming more international to be a very good one.

Looking back, what are your thoughts about the pace of SPE's international growth? Did it happen too slowly? At about the right speed?

Certainly not too slowly; it was an evolution, not a revolution. SPE was already on the right track, and since my term, there have been several non-US presidents. Look at what SPE has become in 15 years—half of the members are now outside the US, we have sections all over the world, and we have opened several offices outside of the US. All of this growth went together with the technical revolution in communication, which was very expensive, along with the creation of a bunch of new meetings all over the world. If you think about it, if it takes 20 years to make an adult, then 15 years to do what SPE has done is not a very long time. In 15 years, we have gained international recognition and respect. It has been a fantastic success.
Overview: Well Stimulation (July 2007)
Authors: Hager Charles
Published: February 2015

For this month's issue of featured well-stimulation papers, the ongoing work in acidizing earns my recognition as the most enlightening and yet overdue progress. Although the papers spotlighted in this issue are strong presentations on diverse subjects, I was most surprised by the volume of engaging papers focusing on acids and fracture acidizing. There are great papers in my list with information on horizontal wells, gravel packing, and viscoelastic fluids; however, each of these technologies is young compared to acidizing reservoir rock.

In one of the additional-reading selections, "Fracture Acidizing: History, Present State, and Future," we learn that acidizing carbonates dates back to 1895. Therefore, the use of acids to increase production is more than a century old. With many of the modern acidizing theories developed around 1972 by Neirode and others, it is still a 35-year-old technology that needs a fresh look with modern methods. Whether we are studying etching behavior to forecast conductivity or predicting long-term reductions in performance caused by creep, we still have a lot to learn about this venerable practice.

Therefore, the question becomes: "How can acidizing oil wells be more than 100 years old, yet we just now are beginning to unravel these fundamental concepts?" The world produces approximately 85 million BOPD, and assuming just USD 50/B, we generate more than USD 1.5 trillion/yr in world oil revenue. Whatever the historical disconnect has been between oil revenues and funding oil science, I am pleased to recommend these compelling technical papers on subjects vital to our industry, including the common practice of pumping acid into a formation to increase production.

Well Stimulation additional reading available at the SPE eLibrary: www.spe.org

SPE 108075 "Horizontal-Well Completion and Stimulation Techniques—A Review With Emphasis on Low-Permeability Carbonates" by Valdo Ferreira Rodrigues, SPE, Petroleo Brasileiro, et al.

SPE 107772 "The Effects of Acid Contact Time and the Resulting Weakening of the Rock Surfaces on Acid-Fracture Conductivity" by M.G. Melendez, Texas A&M University, et al.

SPE 107760 "Acid Stimulation of Extended-Reach Wells: Lessons Learnt From N'Kossa Field" by J.M. Mazel, Total, et al.

SPE 106371 "Fracture Acidizing: History, Present State, and Future" by Leonard J. Kalfayan, SPE, BJ Services