bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improved Operations With a High-Efficiency Jackup
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 105883, "Improvements in Operations Using a High-Efficiency Jackup," by Gordon Hart and Allan Ramsing, Mærsk Contractors, prepared for the 2007 SPE/IADC Drilling Conference, Amsterdam, 20–22 February.
A high-efficiency ultra large jackup rig was used in operations offshore Norway for ConocoPhillips at the Ekofisk field. The rig uses "x-y" cantilever skidding, and it is rigged with a quadruple der-rick with dual standbuilding capability and space for casing racking.

Background
The Marine Structure Consultants CJ-70 type jackup drilling rig Mærsk Innovator is drilling development wells on the Ekofisk 2/4M platform for ConocoPhillips Norway. The rig is to drill 25 of 30 planned wells over a 3- to 4-year period. The other five wells were drilled with the Mærsk Gallant. The wells are a mixture of deviated (up to 80° inclination) and horizontal wells. The program with the Innovator commenced in late November 2005. First, 10 conductor strings were drilled and set. Second, a cuttings-reinjection well was drilled and completed to allow self-sufficient operation in cuttings handling. The final step is drilling and completing the wells. As of November 2006, eight producing wells had been drilled and completed. A further program of batch-setting eight conductor strings was completed during the summer.

Design
In addition to operational performance, these rigs were designed with features to improve safety and environmental performance.Decks clear of ventilators and crane pedestals—allows use of a forklift truck for container handling.Automated pipe-handling system.Enclosed moonpool.Fully enclosed large-capacity mud pits.Automated mud-mixing and solids-control systems.Dual engine rooms—allows maintenance in "quiet" room.Zero-discharge system.Quiet-zone accommodations.Driller's cabin comprising three ergonomically designed workstations.
Increased efficiency was the result of the following.Dual pipe-handling equipment: racking machines and iron roughnecks (two each servicing the well center and the foxhole).Remotely operated pipe-handling machine for transferring tubulars from the cantilever to the drill floor.Casing run in stands.The derrick designed for fourbles of Range-II or thribbles of Range-III drillpipe, resulting in 25% fewer connections.Variable deckload with a capacity in excess of 10 000 tonnes.Three large-capacity cranes with redundancy to cover deck areas.Large deck space and storage capacities for all equipment and consumables.Cuttings-handling and slurrification systems.Slurry-injection system.Proprietory x-y cantilever-skidding systemMoonpool area with capacity to run coiled-tubing or wireline operations offline through a secondary moonpool.

Performance
Of the 54 wells used in the database, the Gallant drilled 11, a Mærsk giant-class rig drilled four, and the remainder was drilled with platform drilling. For the purposes of this comparison, only the Gallant performance was considered.
MODU Performance in Hurricane Ivan
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18322, "MODU Performance in Hurricane Ivan," by B.P.M. Sharples, SPE, Offshore Risk & Technology Consulting Inc., and S. Buffington, U.S. Minerals Management Service, prepared for the 2006 Offshore Technology Conference, Houston, 1–4 May.
Hurricane Ivan tracked through a high-density corridor of mobile offshore drilling units (MODUs) in the U.S. Gulf of Mexico (GOM), resulting in five semisubmersibles losing station and collapse of one jackup. In the aftermath of this hurricane, the industry is reflecting on lessons learned and re-examining industry standards. There was no loss of life and no major pollution from MODUs in Hurricane Ivan. A study commissioned by the U.S. Minerals Management Service (MMS) has chronicled the incidents of Hurricane Ivan to provide information that may lead to more-robust criteria for MODU safety.

Introduction
A study was commissioned by the MMS to gather information and examine MODU loss of station keeping during Hurricane Ivan. There were approximately 112 jackups and 32 semisubmersibles in the GOM at the time of Hurricane Ivan. Only three jackups were affected, and only one of those was a total loss. Five semisubmersibles were affected. Four left their general location and became adrift, and one moved approximately 3,000 ft. Most of the information came directly from drilling contractors, some came from oil companies, and some came from MMS files. Because the study was not complete at the time the full-length paper was written, the information is preliminary and subject to correction and change.

Overview
In September 2004, Hurricane Ivan, a Category 4 storm with waves exceeding the 100-year design criteria for offshore facilities, moved through the GOM. Of the more than 4,000 offshore oil and gas facilities and 33,000 miles of pipelines in federal waters, approximately 150 facilities and 10,000 miles of pipelines were in the direct path of Ivan. Damaged facilities included MODUs, offshore platforms, producing wells, topside systems, and pipeline systems that transport oil and gas ashore. MMS received industry reports indicating that seven platforms were destroyed, six platforms and five drilling rigs had major damage, and a substantial amount of oil and gas production remained shut-in because of pipeline damage.

Semisubmersible MODUs
Ocean Star and Ocean American. Diamond Offshore Drilling reported that drill platform Ocean Star drifted from its moored location. A visual inspection by fixed-wing aircraft confirmed that Ocean Star was afloat with no apparent damage. A visual inspection by aircraft of four other Diamond Offshore rigs operating in the path of Ivan also indicated no apparent dam-age or pollution. The Ocean Star was approximately 1.5 miles east of the storm track. Most of the wires were said to have broken below the rig fairlead near the highest loading point on the system. Hindcast weather data clearly show that conditions exceeded the American Petroleum Inst. (API) 10-year design criteria.
Building Bridges: My Journey Continues… "I Can"
Authors: Cobb Bill 
Published: February 2015

President's column
An email from a student member at King Saud University in Saudi Arabia was the inspiration for this column. Bandar Al-Anazi sent me an animated story about young students who literally bury the "I can't" statements in their lives, and replace them with "I can," "I will," and "I'm going to right away."
This story reminded me that SPE depends on the efforts of "I can" people. Our members keep this organization going by saying "I can" when someone is needed to serve as a section officer, review a paper, plan a conference program, mentor a young member, or take on any of the other multitude of tasks that make SPE the vibrant society that it is.
In most associations, fewer than 10% of the members do almost all of the volunteer work. This hard-core group of "super" volunteers contributes many, many hours each year. I believe SPE does a little better than engaging 10% of our members, but we still tend to turn to the same people over and over again. It is a natural tendency for us all to call on those we know when we need something done. But the consequences are that we risk burning out our tried-and-true people and we miss out on the chance to tap into new talent and resources. We can do a better job of inviting members to serve and letting them know about the opportunities we have for volunteers.
The decision to volunteer is usually a two-step process—a person thinks generally about becoming a volunteer and then a "trigger event" transforms this general thought into concrete action. The "trigger" is often something very simple: someone they know asks them to volunteer in a specific role, or they learn about an opportunity through a general announcement at a meeting, on a form, or in a newsletter.
In my experience, a personal invitation to a specific member nets the best results. Recently, Behrooz Fattahi, who serves on our Editorial Review Committee as co-Executive Editor of SPE Reservoir Evaluation & Engineering, needed additional peer-review help. He obtained a list of members who had indicated on their dues statements an interest in peer review and their field of expertise, and sent invitation letters to them. He got an overwhelmingly positive response, including many comments that they had never been asked before to serve and were pleased to do so!
Techbits: Key Reservoir-Testing Issues Examined by Workshop
Authors: JPT staff _ 
Published: February 2015

Techbits
Eighty-seven participants, representing 48 organizations from 25 countries, attended the SPE Applied Technology Workshop (ATW) "Reservoir Testing in a World of High Production Values," held 11–14 December in Bali, Indonesia.
The ATW comprised 11 sessions, including the keynote address by Tri Siwindono, chief executive officer, PT Pertamina. Siwindono focused on the value of information obtained in reservoir testing and noted that in the current environment of high production values, Pertamina rarely tests oil wells because of the cost of lost production. Most of his company's reservoir tests involve gas wells. He highlighted oil-producing countries' desire to find cost-effective and environmentally protective reservoir-testing methods.
Session 2, chaired by Florian Hollaender, Schlumberger, and Bob Hite, Shell, dealt with new technologies and their applications. Henk Kool, Halliburton, made a presentation on a new bottomhole drillstem-test (DST) -conveyed sampling system. By use of this low-cost system, representative samples are captured under controlled timing and are overpressurized by means of a nitrogen cushion as they are carried to the surface, ensuring that the samples remain representative.
Bertrand Theuveny, Schlumberger, discussed the current and possible future use of multiphase flowmeters (MPFMs). Of the more than 3,000 MPFMs currently deployed worldwide, including 150–200 mobile units, less than 400 are used regularly for well testing. MPFMs have yet to attain full acceptance by operating companies, Theuveny said. Challenges affecting the wider use of MPFMs, he indicated, include the economic limitations of metering low flow rates; bringing accurate multiphase-measurement technology downhole, as opposed to conducting metering at the surface only; making full use of the transient-rate information obtained from these meters; and data-reduction issues related to permanent meter installations or long-term tests.
Ichiro Shikano, Nippon Oil, presented a case study in which a naturally fractured basement reservoir offshore Vietnam was characterized with a combination of pressure-transient tests with tracers. The reservoir-management objectives call for avoiding gas and/or water breakthrough. Water injection is used to manage the gas/oil and oil/water contacts, a challenge in the highly heterogeneous fractured configuration. To assess interwell communication, different tracers were introduced through injectors in different parts of the field, enabling a simple estimation to be made of the source of the water. Although the data-acquisition scheme did not resolve all uncertainties, the simulation model was updated on the basis of the interwell communication results, and a better history match was achieved.
Environmentally Safe Waste Disposal: Integration of Cuttings Collection, Transport, and Reinjection
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 108912, "Environmentally Safe Waste Disposal: The Integration of Cuttings Collection, Transport, and Reinjection," by A. Alba, SPE, F. Fragachan, SPE, A. Ovalle, SPE, and T. Shokanov, SPE, M-I Swaco, prepared for the 2007 SPE International Oil Conference and Exhibition in Mexico, Veracruz, Mexico, 27-30 June. The paper has not been peer reviewed.
Many regulatory agencies are demanding zero-discharge policies, requiring all generated wastes to be disposed of in a responsible manner. This requires adequate management of wastes generated during drilling operations, including cuttings, excess drilling fluid, contaminated rainwater, produced water, scale, produced sand, and production and cleanup waste. Old practices involve temporary box storage and hauling waste products to a final disposal site. Often, these sites are several kilometers away from the generation source, creating not only liabilities for the operating company but also environmental risks.

Introduction
The three main drivers for selection of a cuttings-collection and -transport system and reinjection package are regulations, logistics, and cost. Depending on the country, region, or marine area, the existing regulations may or may not allow discharge or transportation of waste. In some areas where regulations are less stringent, transportation of generated waste to satellite disposal sites (on land or offshore) is allowed. In highly sensitive areas where zero-discharge policies are enforced strictly, all generated waste must be stored, treated, and disposed of in situ. Because of such limitations, drilling operations often are limited by collection capacity and ability of the cuttings-reinjection (CRI) system to inject all waste concurrently. A new approach is to decouple the injection process from the drilling operation, providing a totally independent cost-effective process.
For logistics, the main limitations are determined by rig configuration, space availability, material type, distance of material transportation, and safety, which ultimately translate into costs. Each operation should be analyzed individually to determine logistics, cost, and compliance with local regulations, so proper collection, transport, and reinjection packages are tailored to fit the specific needs of the project.

CRI
In general, CRI is a process wherein solids (cuttings) and liquids (waste fluids) are gathered and conveyed to a series of components that classify, degrade, mix, and condition them into a stable and pumpable slurry. This slurry then is injected into a subsurface formation that is receptive and permanently isolated at a safe depth beneath caprock to prevent migration to the surface.
Technology Focus: HP/HT Challenges (April 2008)
Authors: MacAndrew Robert 
Published: February 2015

Technology Focus
Our industry is faced with addressing new challenges in finding, appraising, and then exploiting HP/HT reservoirs. As the operating envelope continues to be stretched, new design and operational challenges are faced when contemplating new projects. Meanwhile, fields that have been put into production often will present problems not thought of before and, therefore, not accounted for in the original field-development plan.
We are finding that assumptions, practices, and designs that have served us well historically are no longer valid or fit for purpose for HP/HT wells. Because we must redesign existing downhole equipment and develop new equipment, we must maximize the use of modern design aids from the beginning of the design process to speed up the process and limit the risk of unexpected problems during product development and initial field application. There is one important aspect here: These modern design tools, such as finite-element analysis, while powerful, still require experienced engineers to ensure optimal application and benefit. So our need for high-quality engineers continues unabated. Many techniques such as perforating and production-chemical treatments must be re-examined carefully to ensure that they are applied properly to HP/HT wells because many assumptions and treatments that are used successfully in normally pressured wells at lower temperatures will prove inadequate in HP/HT applications and may result in considerable financial loss.
One area in which the industry appears to be going backward is in drilling, particularly in tripping performance. Anecdotal evidence indicates that tripping rates are half of what they were 20 years ago. There are good reasons for slower tripping rates in certain areas of any well, but a general reduction? Did mechanization of the rig floor cause this, or are other factors at work in concert with mechanization? It is strange that this is an area that has not come under pressure from operators, who are continually striving to improve performance in other areas of the industry, particularly with rig rates at the current high levels and drilling costs becoming a greater proportion of development costs. While newer techniques, such as casing while drilling and managed-pressure drilling, can contribute considerable cost savings, they are not universal and we should not ignore the basic methods by which the majority of wells are drilled.
The challenge continues and gets ever more interesting.
HP/HT Challenges additional reading available at the SPE eLibrary: www.spe.org
SPE 108174 • "Reducing Drilling Risks in a Highly Overpressurized Formation: A Case History in Nororiente Basin, Argentina" by M. Frydman, SPE, Schlumberger Geomechanics, et al.
SPE 108656 • "Harsh-Environment HP/HT Gas/Condensate Production Cleanup Experiences—Kristin Field" by Arild Fosså, Expro, et al.
SPE 108432 • "Dual Subsea Choke Applications for High-Pressure-Reservoir Development" by Weihong Meng, SPE, Fluor Corporation, et al.
Q&A with Patrick Pouyanne Senior Vice President, Strategy, Business Development, and Engineering Research and Development, E&P, Total
Authors: Parshall Joel 
Published: February 2015

Q&A
The economic assumptions undergirding everyone's business outlook have changed completely over the past half-year, to say nothing of the price of oil. How is Total responding to that, in terms of upstream strategy, the amount and direction of E&P capital spending, and the implementation of projects?
We didn't discover just today that we are in a cyclical industry. It is true that since 1999, the price of a barrel essentially has climbed, but this is nothing new. We think that it is a good time to demonstrate that the business model of major companies like Total is the right one. Why? Because we have the financial robustness that will allow us to go through such a cycle. Basically, our view is not to make any stop-and-goes in our investment policy. We think that if you are strong enough to continue to invest in the lower part of the cycle, then you will benefit on lower costs, and when the high cycle comes back again, you will benefit from such investments. So of course to do that, you need to be financially robust, which is our case.
We need to keep our long-term view, which is that between supply and demand, the demand will continue to grow, thanks to Asian markets and for the supply it will be difficult to grow it beyond a certain level. The price of energy, which will have to take into account the future costs of development of unconventional plays obviously will climb. So on a mid-term and long-term basis, we are of the view that the price will be higher than today. So we want to keep acting now. When you are in the upstream business, you look at not only the short-term price but the long-term price. Otherwise, you don't make the right business decisions.
So basically what we are going to do is to keep our investment program—keep the volume of projects that we forecasted 1 year ago. But the value of this program should be lower because the costs have to come down and to reflect the general trend of the world economy. On the other side, we will be very rigorous on the operating expenditures. We have requested all of our subsidiaries to control and cut down their operating expenses. So we are preserving our future, keeping the capital expenditures, but being tough on short-term expenses.
What are some of your biggest upcoming projects?
In 2009, the main big project that we have to sanction is CLOV in Angola, Block 17, which is a deepwater project, and Laggan in the UK North Sea. Most of our big projects to sanction are coming in 2010. We have Shtokman in Russia, Ichthys in Australia—another huge LNG project—and then Joslyn, an oil-sand mining project in Canada in 2011. We are in front-end engineering for these projects at present, and all of that is continuing.
Gjøa Development Opens New Frontier
Authors: Sheehan John 
Published: February 2015

In the best tradition of Nordic polar explorers of the past, StatoilHydro is pushing into frontier territory with its Gjøa field development in the Norwegian sector of the North Sea.
Gjøa, named after the fishing vessel used by Norwegian Roald Amundsen to become the first explorer to navigate the treacherous Northwest Passage, is itself heading into uncharted waters. StatoilHydro hopes the development could open up a whole new area of the Norwegian Continental Shelf for modern day oil and gas pioneers.
The Gjøa field and the Vega and Vega South satellites will be developed at a cost of around NOK 38 billion (USD 5.7 billion) with a new semisubmersible platform, which will sit in 1,210 ft (370 m) of water 45 km off the southwestern coast of Norway.
Recoverable reserves for the field are put at 82 million bbl of oil and condensate and roughly 1.4 Tcf (40 Bcm) of gas. Vega and Vega South's recoverable reserves are estimated at 26 million bbl of condensate and 636 Bcf (18 Bcm) of gas. Drilling work to tap the fields’ reserves is already under way and a pilot well is currently being drilled to further delineate the field.
It is full steam ahead on all fronts as Gjøa Project Director and Vice President for Field Development, Kjetel Digre, explains: "Everything is happening right now. We have just started on the actual drilling and completion program on the field.
"We are just about half way through the build program, which is 58% complete. We are close to finishing the hull in South Korea. The major components will be brought to Aker Solutions’ yard in spring for assembly in the autumn." The 15,650 ton hull is being built by Samsung in South Korea and it will be mated with the topsides at Aker Solutions’ yard in Stord, Norway. The topsides includes a 22,000 ton deck and the capacity to accommodate 100 offshore workers will be provided by a 1,650-ton living quarters module, with helideck. The living quarters are currently under construction at Leirvik Module Technology in western Norway. StatoilHydro is operator for Gjøa in the development phase, while Gaz de France takes over as operator when the field comes on stream. Licensees in the license are Gaz de France (30%), Petoro (30%), StatoilHydro (20%), Shell (12%), and RWE Dea (8%).