bluuebunny/crossref_metadata_2025 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%).
Technology Focus: Offshore Drilling and Completion (April 2009)
Authors: Jousseaume Jean-Louis
Published: February 2015

Technology Focus

When reading professional papers, I notice that our profession is innovating more and more.

This trend is related to the increasingly difficult challenges we must accept.

Safety—We are facing more dangers while keeping the risk much lower than before: high-pressure gas fields, very harsh environment, and others.

Environmental issues—Under pressure from authorities, and our conscience that we cannot leave a sea to our children in which they would not dare to swim, we are now applying a very strict control of our wastes.

Colleagues of geosciences—Wells are proposed that encounter greater difficulties. We are running sensitive operations, in complex geological contexts, where the problems are met from the seabed to the targets.

Human resources—We face cyclic activity in which recruitment goes up and down, with no time to train workers correctly in periods of high activity, and no money to train them in slow times. In such a changing context, we must do our best to have an efficient transmission of experience and know-how between the elders and the young recruits, but often we must sacrifice this aspect to immediate needs or constraints.

Economical challenge—We must deal with external events, which makes real stabilization of our activity impossible, and we must control costs in any circumstances: either when activity level is increasing, and dragging along the costs toward unthinkable peaks; or when it is decreasing, with the oil price making projects less economical, forcing us into difficult cost-cutting exercises.

This trend toward increasing complexity is not new, but it is accelerating. As engineers, our best answers to these new challenges are innovation and boldness. Last year was an Olympic year: like high-level sportsmen, we shall, day after day, surpass ourselves to manage our operations "Citius, Altius, Fortius."

Offshore Drilling and Completion additional reading available at the SPE eLibrary: www.spe.org

SPE 115058 • "Case Study: Restoring Sand-Prone Subsea Wells to Production" by M. Vazir, BP plc, et al.

SPE 115698 • "Development and Installation of a Triple Wellhead on the Britannia Platform" by A. Elizabeth Matheson, SPE, ConocoPhillips, et al.

SPE 113701 • "Optimized Recovery From the Fram Øst Development Through Extreme-Well Design" by Arve K. Thorsen, SPE, Baker Hughes, et al.

Additional reading available at OnePetro: www.onepetro.org

OTC 19307 • "Drilling Through Bitumen in the Gulf of Mexico: the Shallower vs. the Deeper" by Gang Han, Hess Corporation, et al.
High-Angle Directional Drilling With 9 5/8-in. Casing Offshore Qatar
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 119446, "High-Angle Directional Drilling With 9⅝-in. Casing in Offshore Qatar," by Michael Avery and Tod Stephens, Occidental Petroleum of Qatar Ltd.; Ali K. Al-Hadad, SPE, Qatar Petroleum; Mounir Turki, SPE, Tesco Corp.; and Malek Abed, SPE, Schlumberger, originally prepared for the 2009 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 17-19 March. The paper has not been peer reviewed.

Horizontal-well programs that require drilling through unstable formations at high angles before entering the productive zone are becoming more common. Casing while drilling (CWD) is becoming a powerful method in mitigating both lost-circulation and wellbore-stability issues in offshore directional wells. As a result of recent advances in tool design, it is now possible to circulate, rotate, and reciprocate the casing during bottomhole-assembly (BHA) retrieval and setting operations without modifications to the rig.

Introduction

Occidental Petroleum of Qatar currently drills a number of offshore horizontal production and injection wells in the Shuaiba limestone formation. Directly above the Shuaiba is the Nahr Umr formation, which is composed of a nonreactive, but unstable, kaolonitic shale. The 12¼-in. section is drilled conventionally approximately 80 ft into the Shuaiba [20 ft true vertical depth (TVD)] at up to 86° inclination, and a 9⅝-in., 47-lbm/ft L-80 casing string is run and cemented to isolate the shale and sand while drilling the 8½-in. reservoir section.

The Nahr Umr/Shuaiba interface is often a point where highly conductive faults are encountered. Severe losses of drilling mud often occur at this interface, resulting in a dramatic reduction of hydrostatic pressure as the wellbore-annulus fluid level falls. This pressure loss causes the unstable formation to collapse on the drillstring and BHA, packing it off and making it practically impossible to retrieve. The Shuaiba exploitation strategy, however, depends on landing wells at near-horizontal angles so that long sections can be drilled in the reservoir.

A potential solution to this problem is to drill the section with casing and a retrievable BHA. Directional CWD technology uses the casing, in place of drillpipe, to convey rotation and torque and act as a conduit for the drilling fluids. The directional BHA is latched to the lowermost casing joint and extends approximately 85 ft out of the shoe. It is driven by both surface rotation and a downhole motor. For this application, an 8½-in. bit is used to drill a pilot hole, which is opened up immediately to 12¼ in. by an underreamer positioned just below the 9⅝-in. casing-reamer shoe. The BHA can be retrieved through the casing at any point during the drilling operation by running in through the casing with drillpipe and a latch tool.
A Process Option To Comply With Zero-Harmful-Discharge Legislation in Norwegian Waters
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 118012, "The CTour Process, an Option To Comply With Zero-Harmful-Discharge Legislation in Norwegian Waters - Experience of CTour Installation on Ekofisk After Startup 4th Quarter 2007," by Kare Voldum and Eimund Garpestad, ConocoPhillips Norway, and Nils Olav Anderssen and Inge Brun Henriksen, ProPure, originally prepared for the 2008 SPE Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, 3-6 November. The paper has not been peer reviewed.

A series of joint-industry projects in conjunction with Norwegian research institutions have developed a solvent extraction process to remove contaminants from produced water. Results from performance testing indicate that the efficiency from the original pilot tests had been reproduced successfully, yielding on a field scale residual oil in water (OIW) of 1 to 2 ppm and naphthalenes and polycyclic-aromatic-hydrocarbon (PAH) reduction by 86 to 92%.

Introduction

The Ekofisk field, operated by ConocoPhillips, is the oldest operating field in the Norwegian sector of the North Sea. It is a carbonate reservoir that has been seawater flooded since 1986. Currently, it is in a stage of increasing water cut that is projected to peak at 41 000 m3/d by year 2015. The Norwegian operators have to comply with the OSPAR (which replaced the Oslo and Paris Conventions) discharge legislation, which states that overboard discharges of hydrocarbons cannot exceed 30 ppm and that the annual total oil discharges cannot exceed 85% of the reported annual discharges of the year 2000. This represents a big challenge for an operator experiencing increasing water cut.

In the Norwegian sector of the North Sea, in addition to the OSPAR legislation, operators must comply with specific Norwegian legislation that calls for "zero environmental impact" from overboard discharges. The environmental-impact factor (EIF) is used as a tool to quantify the harmful effect of discharges to the environment. The EIF was developed as a management tool on the basis of internationally agreed procedures for hazard and risk assessment. The tool models the dispersion of produced water, accounting for volume, composition of oil and aromatic components [benzene, toluene, ethyl benzene, and zylene (BTEX) and naphthalenes, PAHs, and phenols], production chemicals, and heavy metals, and it calculates the predicted-environmental-concentration/predicted-no-effect-concentration ratio.

To comply with the new discharge legislation, ConocoPhillips originally projected to achieve a 95% reduction in EIF at Ekofisk by introducing produced-water reinjection (PWRI). However, after a pilot PWRI test was performed, the conclusion was that reinjection was not cost efficient, and most importantly, it became apparent that it introduced a risk of reservoir souring, and could cause substantial loss of oil produced.
NGH Chain: Gas-Transportation Concept
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 12807, "NGH Chain: A New Gas Transportation Concept," by T. Kawasaki, K. Bando, and Y. Suehiro, SPE, Japan Oil, Gas, and Metals National Corporation, prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3-5 De cem ber. The paper has not been peer reviewed.

In general, long-distance liquefied natural gas (LNG) transportation projects are economically feasible for very large natural-gas reserves volumes. Japan Oil, Gas, and Metals National Corporation and Japanese engineering companies have focused on natural-gas hydrate (NGH) as a gas-transportation concept. It is important to consider optimizing the process and to understand the effect on the chain and optimize the entire NGH chain.

Background

Many medium and small gas fields within 6000 km of Japan are difficult to develop by conventional techniques, such as LNG and pipelines. NGH may be an economical gas-transportation method. NGH contains 170 times the gas volume compared with liquid or gaseous states. Therefore, initial cost of the NGH process is estimated to be less than that for LNG.

LNG transportation is economically feasible for long-distance transportation. Pipelines are suitable for relatively-short-distance transportation because of higher capital cost. NGH transportation is a solution for small-to-medium-scale or remote gas fields, as shown in Fig. 1. Feasibility studies shown in Fig. 2 indicate that NGH transportation has an economic advantage for suitably sized gas reserves and transportation distance.

Several systems have been developed to form NGH, including the bubbling/stirring-type formation reactor, the water-spraying-type formation reactor, and a hydrate-formation system that uses microbubbles with a tubular reactor, which obtains a higher formation rate than the other systems. Further improvement is needed in the precision of the feasibility study along with advances in technology.

Conceptual Design

The purpose of this study was the life cycle carbon dioxide (LCCO2) analysis of natural-gas transportation to Japan as NGH. In the selected model, natural gas is converted to NGH at the production plant and delivered to Japan by an NGH-carrier ship from existing undeveloped natural-gas fields in coastal areas of Southeast Asia. The base case production rate was 1×106 tonnes/a of LNG equivalent with a transport distance of 6000 km. The study presumed that the gas would be used in a power plant.

LCCO2 Analysis

The scope of investigation includes processes between the production facilities (including inlet-gas treatment) and the regasification facilities.
Q&A with Don Paul
Authors: Paul Don , Donnelly John
Published: February 2015

Q&A - No abstract available.
Spotlight on R&D: Drilling and Completions - Striving for the Par-5 "Hole in One"
Authors: Willson Stephen , Armagost Ken
Published: February 2015

Spotlight on R&D series - This is the third of a series of articles on the state of research and development (R&D) in the major upstream technological disciplines. The Spotlight on R&D Series, comprising articles published in JPT during 2004 and 2005, is available as a collection on OnePetro (SPE-101432-JPT).
Keys to Success in Deploying Scalable Visualization Technologies
Authors: McFarland Charles , Fleitman Ari
Published: February 2015

Management - No abstract available.
The Role of the Annular Gap in Expandable-Sand-Screen Completions
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 86463, "The Role of the Annular Gap in Expandable-Sand- Screen Completions," by J. Heiland, J. Cook, SPE, A. Johnson, SPE, and B. Jeffryes, SPE, Schlumberger Cambridge Research, prepared for the 2004 SPE International Symposium and Exposition on Formation Damage Control, Lafayette, Louisiana, 18-20 February.
Overview: Artificial Lift (May 2004)
Authors: Prado Mauricio G.
Published: February 2015

Overview - No abstract available.
Effects of Transient-Flow Conditions on Electrical Submersible Pumps in Sinusoidal Well Profiles
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 84134, "Impact of Transient- Flow Conditions on Electrical Submersible Pumps in Sinusoidal Well Profiles: A Case Study," by S.G. Noonan, SPE, M.A. Kendrick, and P.N. Matthews, ChevronTexaco EPTC; N. Sebastiao, SPE, ChevronTexaco Overseas Petroleum; and I. Ayling, SPE, and B.L. Wilson, SPE, Baker Hughes Centrilift, prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5~8 October.
Robust Determination of the Pore-Space Morphology in Sedimentary Rocks
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 84296, "Robust Determination of the Pore-Space Morphology in Sedimentary Rocks," by Dmitry B. Silin, SPE, Lawrence Berkeley Natl. Laboratory; Guodong Jin, SPE, U. of California, Berkeley; and Tad W. Patzek, SPE, U. of California, Berkeley/Lawrence Berkeley Natl. Laboratory, prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
Characterization of Water Injection in Low-Permeability Rock Using Sandstone Micromodels
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 86964, "Characterization of Water Injection in Low-Permeability Rock Using Sandstone Micromodels," by Wei Sun and Zhihao Qu, Northwest U., Xian, People's Republic of China, and Guo-Qing Tang, SPE, Stanford U., prepared for the 2004 SPE International Thermal Operations and Heavy Oil Symposium and Western Regional Meeting, Bakersfield, California, 16-18 March.
The Petroleum Engineer's Role in Conservation
Authors: Wyman Tom
Published: February 2015

The petroleum engineer is at the very heart of the oil business. It is challenging, even exciting, work wresting energy from the clutches of Mother Nature. We know that all of our industry associates in down-stream operations (pipeliners, tanker operators, refiners, and marketers) depend on us to keep the oil flowing. More importantly, the public worldwide—civilization, if you will—relies on the geologist and petroleum engineer to continue to find and produce the oil and gas that everyone takes for granted and consumes at such an enormous rate.

Geologists and rate-of-discovery statistics tell us how difficult it is simply to keep even with the annual depletion of reserves and, of course, how much harder it is to add to reserves. Petroleum engineers know how difficult it is to delay the inevitable production decline in a maturing oil field. They know the technological challenges of squeezing out the final barrels of oil from a near-depleted reservoir. And they realize how important it is to find new ways to stretch waning production and maximize the ultimate production from each reservoir and field.

Today, the field of petroleum engineering is not simply a job or a career opportunity, but like the professional medical caregiver, it carries with it a responsibility to society. Adequate supplies of oil and gas are essential for societies worldwide, and they will continue to be so for the foreseeable future. Although consumers of petroleum products are not aware of how the industry works, they rely on petroleum engineers to produce more and more from the world’s increasingly hard-to-find oil and gas fields. The petroleum engineer is the one who best knows the effort that goes into simply maintaining production levels, not to speak of increasing production to meet growing demand.

As petroleum engineers, we need to tell people what we do. Petroleum engineers have been in the business of energy conservation for years. We conserve oil as we produce oil. To a petroleum engineer, conservation means “squeezing” as much oil out of each reservoir as possible. It means saving energy by operating more efficiently and by using less oil and gas today than we did yesterday. It means calculating the maximum efficient rate of production so that ultimate production from each oil field and each gas reservoir is maximized. Natural gas may be reinjected into the producing horizon to maintain reservoir pressure, thereby increasing ultimate oil production. Water may be injected to sweep oil reservoirs and increase ultimate recovery. Wells may be stimulated and reservoirs heated to accelerate the flow of oil into the wellbore. Reservoirs and adjacent areas are meticulously mapped to reveal subtle, overlooked traps. In any enterprise, energy conservation is a direct means of adding to the bottom line. If Benjamin Franklin had been in the oil industry, the quotation from Poor Richard’s Almanac might have read: “A barrel saved is a barrel discovered.”
Q&A with Antonio Suarez
Authors: Suarez Antonio , Donnelly John
Published: February 2015

Antonio Suarez is Director of New Ventures for Repsol YPF and Chairperson of the Local Advisory Committee for the EAGE/SPE Europec Conference. With more than 25 years in the oil industry, Suarez has worked on exploration assignments in Africa and Latin America for Hispanoil and Chevron Overseas, and for the last several years, he has been responsible for identifying, evaluating, promoting, and negotiating new E&P projects for Repsol YPF. He has worked on Repsol YPF projects in Libya, Algeria, Venezuela, Mexico, Iran, Saudi Arabia, and west Africa. He earned an MS degree in geophysics from Stanford U. and an MS degree in finance from the London Business School.

As Chairperson of the EAGE/SPE Europec Conference, can you offer some highlights of the conference?

This conference is unique, as it brings together two great associations and will join geologists, geophysicists, and engineers into looking at our business in a more multidisciplinary way. There will be specific workshops and sessions on various technical and industry topics. Ours is an industry that relies on technology, and looking at things in a broader, integrated way is essential. Sharing knowledge is very important to the development and improvement of the industry. We are expecting about 4,000 people to attend, and it will be a truly integrated, global event.

This conference represents the first full collaboration between EAGE and SPE in this event. What is the significance of that?

That is what makes this event unique. The strong cooperation between the associations makes this conference more global and gives it more perspective. And being in Spain, there is a natural bridge to Latin America and north Africa. It is an excellent opportunity to bring together professionals from these regions, in addition to the Middle East, the Former Soviet Union (FSU), and North America, in an expert conference of this type.

You are chairing a session on how national oil companies (NOCs) view the E&P industry. Do you believe that there has been a shift in how NOCs are approaching the upstream?

The boundary between NOCs and the international oil companies (IOCs) is getting narrower and more confused. It is a more open world nowadays. Many NOCs are competing in different ways now—Petrobras, Petronas, Statoil, for example. NOCs now compete globally, and places like Mexico and Saudi Arabia—countries that were formerly closed—are opening up and attracting IOCs.

This is a good time to listen to what traditional NOCs have to say about what is taking place, particularly regarding access to technology. The easy oil is gone for the NOCs, so they are going beyond their former boundaries in search of oil and projects. Pemex, for example, is looking at the deep waters of the Gulf of Mexico for this reason. Things are changing significantly. Our panel has invited representatives from the main producing countries of the world, including Saudi Arabia, Libya, Algeria, Mexico, Iran, and Venezuela.
Spotlight on R&D: R&D Is an Astute Investment
Authors: Judzis Arnis , Hill A. Dan
Published: February 2015

Spotlight on R&D series - This is the last of a series of articles on the state of research and development (R&D) in the major upstream technological disciplines. The Spotlight on R&D Series, comprising articles published in JPT during 2004 and 2005, is available as a collection on OnePetro (SPE-101432-JPT).

In January 2004, the SPE R&D Advisory Committee kicked off a series of guest articles in this journal to articulate and promote the benefits of R&D in the upstream oil and gas industry. Authors well known in the industry articulated not only the challenges but also the successes of R&D in all SPE disciplines: Drilling and Completions; Facilities and Construction; Reservoir Description and Dynamics; Production and Operations; Health, Safety, and Environment; and Management and Information.

The SPE Board of Directors formed the R&D Advisory Committee in 2002 at the recommendation of the R&D Task Force. Its goals were to “identify, encourage, facilitate, and help global R&D activities that will provide needed technology for future use by petroleum engineers.” The committee has begun a number of initiatives that are visible in the industry and particularly for individuals and companies involved in SPE. The R&D Advisory Committee has taken a lead in the following areas:

1. R&D Providers Directory

The R&D Providers Directory was launched on 28 February 2005. It connects universities, research institutes, and other organizations that perform R&D for the upstream oil and gas industry with companies seeking technology applications. The directory can

- Describe facilities, expertise, and types of R&D performed.

- Highlight special features that make the university/institute unique.

- Describe recent and ongoing research projects.

- Identify faculty or principal researchers and their qualifications. The information is fully searchable by companies looking for R&D expertise and is available at www.spe.org. For more information about listing an organization in the R&D Providers Directory, please contact SPE at rdprov@spe.org.

2. R&D Session at the SPE Annual Technical Conference and Exhibition

At this year’s SPE Annual Technical Conference and Exhibition (9–12 October in Dallas), an R&D panel discussion will focus on upstream research activity and the perception that its decline has not only decreased the direct research efforts of operating companies but also reduced their participation in collaborative research activities with academia, government laboratories, and private research companies.
Overview: Artificial Lift (May 2005)
Authors: Prado Mauricio G.
Published: February 2015

I can still remember the time and effort spent with pressure-traverse curves to analyze or design artificial-lift systems in the early 1980s. Here we are a quarter century later with the mission of training new engineers coming into this industry to work on a routine basis with sophisticated computational tools, to analyze real-time data, and to develop tools and use them for real-time monitoring and optimization of artificially lifted wells.

In my view, the two most important abilities a new engineer must master are as follows. First is the ability to use his/her technical background and good engineering judgment to use and interpret the results from this combination of sophisticated tools and endless flow of data. Second is the ability to work efficiently in multidisciplinary teams.

The complexity of current production systems in deep waters involves many risks, and the stakes are very high. Good data and accurate, sophisticated models enable us to have more confidence in engineering predictions, but only a team approach is capable of producing creative solutions that take into account the many constraints from several disciplines.

The selection of papers featured in this issue serves as a small sample of the interesting work being conducted in the area of artificial lift.

Additional Artificial Lift Technical Paper

Available at the SPE eLibrary: www.spe.org

SPE 90153 PCP Axial Load: Theory and Lab Results