bluuebunny/crossref_metadata_2025_split huggingface dataset:
Overview: HP/HT Challenges (March 2006)
Authors: MacAndrew Robert 
Published: February 2015

During my tenure as reviewer for the HP/HT feature, I have seen trends and areas of new activity as well as problems addressed in the papers reviewed each year for inclusion in this feature. This year has been no exception, with a wide range of subjects; showing how the push toward HP/HT production presents challenges to our industry as the boundaries of existing technologies are pushed outward, first slowly and then with more vigor and surety.
The industry is pushing the drilling-technology frontier forward with enthusiasm, despite the high costs. However, the capabilities of available completion equipment are in danger of being left behind this headlong rush by the geological and drilling fraternities. In discussions with those concerned with providing completions for the ever deeper and hotter wells, it is clear that they are, to an extent, struggling with the old problem of the materials world: the lack of any "free lunch." Therefore, completions engineers are engaged in the struggle of finding materials to provide these wells with reliable completions.
One issue, voiced more than once, is the problem resulting from the general reduction in basic engineering research by the major oil and gas companies. As operators reduced their research activities, the service sector has been left to take up the slack. However, one senses reluctance by the service industry to take up the slack. The anecdotal evidence is that the service companies do not feel comfortable taking on the commercial risks involved in developing new or significantly enhanced products. The reasons for this, no doubt, vary from company to company, but if a significant technology gap develops between equipment requirements and availability, then HP/HT developments may stall, or operate with equipment that may have questionable reliability. While not necessarily jeopardizing safety, this gap can present a considerable risk to operating costs. The industry should address this issue to ensure that existing mechanisms of fostering equipment development are functioning and are strong enough to meet the industry's needs.
One last thing: Where are the engineers to drill, complete, and operate these wells? Operators are struggling to fill positions required to produce these generally demanding wells. Requirements to fill these positions are being lowered in the search to find candidates. And once these less experienced candidates are in place, does experience exist within the company to manage these people? Thoughts along the lines of "here we go again" spring to mind!
HP/HT Challenges additional reading available at the SPE eLibrary: www.spe.org
SPE 97018 "Evaluation of Equivalent Circulating Density of Drilling Fluids Under High-Pressure/High-Temperature Conditions," by O.O. Harris, SPE, U. of Oklahoma, et al.
SPE 97582 "Alternatives for High-Strength Materials in Sour Environments," by G. López Turconi, Tenaris, et al.
available at the OTC Library: www.otcnet.org
OTC 17315 "New Bundled Hybrid Risers for HP/HT Applications," by P. Sauvage, Doris Engineering, et al.
Techbits: Meeting Examines History-Matching Advances, Future Challenges
Authors: JPT staff _ 
Published: February 2015

History-Matching may have made significant advances during the past 10 years, but the lack of industry standards and other challenges could prevent the discipline from being universally accepted. A recent Applied Technology Workshop titled "History Matching: New Developments and Best Practices" identified the current benefits of and future needs for the technique that matches geological models to field production data, with the ultimate goal of predicting future reservoir output.
The meeting's 90 attendees represented a cross section of engineers, geoscientists, and academicians. This diverse group not only had different levels of experience in implementing history matching but also employed many different approaches, which they shared freely. "In general, there was a broad consensus that there is no single best approach to history matching and no uniform approach across the industry," said Akhil Datta-Gupta, who holds the LeSuer Chair of Petroleum Engineering at Texas A&M U. and was Chairperson of the workshop. Many attendees agreed that the approach taken is often tied to the process and the decisions to be made. "It is important to identify model objectives at the outset and define the attributes of a good history match," Datta-Gupta said. "In general, a structured approach to history matching allows us to easily reproduce the results and transfer the technology to younger engineers."

What Is Best, What Is Missing
The five major topics discussed at the Houston-based event were Workflow and Best Practices, Field Applications and Case Studies, Assisted History Matching/Inverse Modeling, Uncertainty Assessment, and New Developments. Within each topic discussion, there were the recurring themes of what is best about today's history-matching technology and what is missing. Mike King, Senior Adviser, Reservoir Modeling and Simulation for BP America Inc., gave the first keynote address, focusing on the extent to which history-matching technology has changed over the past decade. "Ten years ago, SPE held a forum on history matching, and it is interesting to see that some of the techniques addressed then are now reaching a level of maturity where we can apply them," he said.
A decade ago, many geologists and engineers held a negative view of the technology because they thought it was taking reservoir analysis out of their hands. "Over the past decade, our understanding of what the technology can do has matured to the point where people can characterize a reservoir's performance in ways that were impossible just 10 years prior," King said.
Datta-Gupta said the advancements over the past 10 years have taken various forms, and have includedIntegrated-workflow tools.Software for handling and assessing multiple models and simulations.New history-matching algorithms.The use of streamline-based approaches and experimental design/response surfaces.
Swelling Packers Solve Zonal-Isolation Challenge in Oman High-Pressure Wells
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 100361, "PDO's Proactive Approach To Solving a Zonal- Isolation Challenge in Harweel HP Wells Using Swell Packers," by M.S. Laws, SPE, (now with Shell Abu Dhabi B.V.), J.E. Fraser, SPE, and H.F. Soek, SPE, Petroleum Development Oman, and N. Carter, SPE, Easywell UAE (now with Sensornet Ltd.), prepared for the 2006 IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, Bangkok, Thailand, 13–15 November.
The Harweel cluster of reservoirs in southern Oman is Petroleum Development Oman's first enhanced-oil-recovery project. Zonal isolation is crucial to the success of the planned miscible-gas-injection project. Previous isolation attempts using cementing technology alone have proved to be unsuccessful. On the basis of results obtained from both laboratory and field tests, swelling packers in combination with cement have demonstrated zonal isolation in these challenging high-pressure reservoirs. This could enable a significant increase in reserves and, hence, ultimate recovery in these fields.

Introduction
The Harweel cluster consists of nine different deep, highly pressured reservoirs containing sour, light hydrocarbons. More than 50 wells have been drilled in and around these fields. The initial wells have a shallow 13 3/8-in. surface casing, a long 9 5/8-in. production casing, a 7-in. liner cemented over the reservoir section, and 3 1/2-in. production tubing.
The cluster is being developed in a phased manner. The objective of Phase 1 was to gather data from a number of different sources to determine if a miscible-gas-injection project would be feasible in some of these fields. Phase 2 will involve primary depletion in a number of fields followed by gas injection in some, and Phase 3 will involve clusterwide depletion and gas injection in the remaining fields. To maximize ultimate recovery from these fields, gas (and water) shutoff is required during Phases 2 and 3 of the project. For this to be effective, zonal isolation over the reservoir is essential.
A substantial effort has been expended during construction of the Phase 1 wells to determine if zonal isolation was being achieved with standard cementing techniques. Cement-bond logs were run over the liner section in every well to determine cement quality. These logs showed that a microannulus was being created in practically every case. During well completion, cement debonding from the production liner occurs as a result of differential-pressure effects that lead to creation of a microannulus. Once the microannulus is created, a permanent flow path between the cement and production liner can be created, preventing zonal isolation.
Selective perforating during the subsequent well-testing campaign showed that this microannulus was conductive to reservoir fluids (Fig. 1). In one incident, reservoir fluids leaked all the way to surface through the microannulus.
Q&A with Emmanuel Egbogah, Special Adviser to the President of Nigeria on Petroleum Matters
Authors: Egbogah Emmanuel O. , Donnelly John 
Published: February 2015

Q&A
Regarding your new appointment as special adviser to the President of Nigeria on Petroleum Matters, what does your position involve?
My position is to advise the president of Nigeria on anything to do with petroleum, including legal aspects, policies, and strategies. The Nigerian petroleum industry is my responsibility. In the immediate term, I am involved in the restructuring of the public sector of the oil and gas industry in Nigeria. That is my immediate task because in the past the oil industry has not done as well as it should have. A lot of the laws are very old and out of date so I am involved in updating laws and policies. We are repealing many laws and enacting new ones to be able to make the changes in the industry that we want to occur. Those changes are very fundamental and very profound and will change the way the oil industry operates in Nigeria.
Can you describe what kinds of changes you would like to see happen?
For instance, we have created a structure that derived from the highest level of authority in the government, what we call a superministerial council, the National Energy Council, which will be chaired directly by the president himself. This council, which includes ministers of the government and myself, will supervise the restructuring and the complete reorganization of the national oil company, the Nigerian National Petroleum Corporation (NNPC). In the past, NNPC has engaged in what I call a conflicting role in legal, commercial, and regulatory policies. It is not possible that a company could police itself, so we are now going to separate the various functions of the company.
The new company, which is going to be called the National Petroleum Company of Nigeria, will engage purely in commercial activities and function as an integrated national company that can go to the stock market and raise money to carry out its operations. It will be regulated by a new agency, called the Petroleum Inspectorate Commission, which replaces the Department of Petroleum Resources in Nigeria. That commission will have the authority to regulate, including the international oil companies (IOCs) operating in the country.
We will have a dual regulation structure—one body to oversee the upstream and another to oversee the downstream, called the Petroleum Development Administration. These functions will be clearly defined so that the roles no longer will be conflicting and self-defeating. We believe that this kind of structure will give clarity, efficiency, and professionalism to the oil and gas industry in Nigeria.
Crystallography: The Long-Term Price of Oil
Authors: Moncrieff Ian 
Published: February 2015

Management
It seems only the proverbial blink of an eye since the principal determinants of the price of crude oil on world markets were the tax-paid cost of the Burgan field in Kuwait and the producing allocations decided by the Texas Railroad Commission. Crude oil was in such abundant supply 50 years ago that British Petroleum, then half-owner of the Kuwait concession, and the world's largest oil producer by far, sold more than half a million BOPD of its share of production to its partner, Gulf Oil, at the overlift price, one-eighth way between the accounting cost of production (then about USD 0.80/bbl) and the posted price of USD 1.75. Gulf Oil turned around and resold most of its Kuwait overlift oil at a larger profit, and nobody seemed to care. The world was awash in oil. On the domestic front, supply was so abundant that Texas oil wells were permitted to pump for only 97 days in 1958.
Suffice it to say that we no longer exist in a world of oversupply. West Texas Intermediate (WTI) futures on Nymex briefly crossed the USD 100/bbl threshold in late 2007. Alberta has become the new Kuwait, and the Texas Railroad Commission figuratively relocated from Austin to Vienna and became OPEC. Like the Seven Sisters before them, OPEC has attempted to control the price of oil on world markets, with Saudi Arabia shouldering the role of market regulator. While the majors showed impressive solidarity in their dealings with foreign governments, the supply fundamentals were not in their favor. The nationalization of IPC's holdings in Iraq, for example, was precipitated by the refusal of the majors to develop new Iraqi oil fields when there was already too much oil on the market.
So what has happened to trigger the more than seventy-fold increase in the price of oil since the 1960s, when the arm's-length price of Kuwait crude was around USD 1.35/bbl, and what lessons may we glean from this history as we peer intently into the crystal ball of price predictions?

The Lessons of History
As Winston Churchill famously remarked, "Those that fail to learn from history are doomed to repeat it." Three principal forces have been at play over the past 50 years, and we would be remiss in ignoring them.Population and economic growth, which powered world consumption of refined products to grow from 21.3 to 84.4 million BOPD between 1960 and 2006.Cumulative oil production since 1960, which, notwithstanding published recoverable-reserves estimates to the contrary, exceeded reserves additions.The remarkable adaptability of consumers to higher prices, abetted by frequently undisciplined or short-sighted government policies that encourage inefficient use of transportation fuels.
Your SPE: SPE Meetings Evolve to Respond to Technology Needs
Authors: Roodhart Leo 
Published: February 2015

President's column
SPE's principal aim is the transfer of technology. This is achieved in a number of ways, including events, publications, and online resources. I believe we are successful in this mission, which largely accounts for why the Society has a growing worldwide membership.
One of SPE's proudest traditions is the longstanding and continuing quality of its events. My schedule as President is driven partly by major SPE events; if I can combine attendance at a conference with a visit to local sections, this is the ideal trip and potentially adds the most value for SPE and its members. Since I have so much to say about technology transfer, I am focusing this month on events and will talk next month about publications, online resources, and other exciting future plans.
Some of the oldest SPE events still retain their top billing in the oil industry calendar, as they have evolved over time to meet the requirements of delegates and exhibitors alike. Offshore Europe, for example, held every 2 years in September in Aberdeen, has come a long way from its early beginnings in the mid-1970s when the event was held in marquees at the University of Aberdeen. The 2007 show broke all previous attendance records, with daily visitors in excess of 40,000 and over 1,450 exhibitors. The 2009 show has grown another 10% in size and has a waiting list for exhibit space. The international presence has never been greater, with pavilions from all parts of western Europe, three large pavilions from China, and, for the first time, from Spain and Brazil.
One of the most exciting developments over the past 10 years is the addition of major exhibitions and conferences in places like Latin America and Russia. As SPE membership becomes more international, we need to take quality events to more corners of the globe to encourage maximum participation. As is the case with the more established shows, these events feature a more interactive debating style, which makes for much livelier and interesting presentations. This does not detract from the quality of technical information presented; indeed, SPE is way ahead of the commercial event organizers and many professional societies in its system of first requiring technical papers for most of its conferences and then archiving all conference papers for reference by members worldwide in the SPE eLibrary and in the multi-society OnePetro. I will talk more about this next month.
Comments: Price Swings
Authors: Donnelly John 
Published: February 2015

Editor's column
A new report from Ernst & Young seeks to find a bottom for commodity prices and any signs that might point to economic recovery. Among its findings are that the recent oil price fall was the steepest ever, at 75%, and that past price corrections have lasted an average of 73 weeks before recovering. Because recessions eventually have given way to economic resurgence that relies heavily on energy, the report concludes that now is the time for the oil and gas industry to prepare for economic recovery by continuing to drill, ensuring that it is retaining talent, and investing in alternative fuels.
Others have sounded a similar note of late. At last month's annual Cambridge Energy Research Associates (CERA) conference, executives from BP, Shell, and other firms noted the importance of continued investment in energy. Robust long-term growth forecasts for hydrocarbons have not changed, and the industry could be caught flat-footed when the recovery comes if it shuts down too much now. Shell Chief Executive Jeroen van der Veer said he believes that global energy demand still will double over the next 40 years, boosted by consumption from the developing world. BP Chief Executive Officer Tony Hayward also showed optimism. "The world economy will recover," he said. "The future is not canceled." (For additional reporting on the event, go to JPT Online at www.spe.org/jpt.)
The statements lend credence to the idea that many in the industry are trying to avoid some of the mistakes of the past, when R&D and staff were sharply cut in the wake of down cycles. But nothing paralyzes the oil market so much as price instability. After the steep drop in prices in the second half of last year, oil seemed to be recovering, only to fall again and remain volatile. Such unexpected swings deter decisions about investment, particularly those projects with sensitive price thresholds such as oil sands and unconventionals.
Volatility also hampers merger and acquisition activity. Sellers are reluctant to shed assets at low prices while potential buyers continue to sit on cash. "Nobody has been willing to pull the trigger. Everybody has been waiting for the upside," said IHS executive Linda Kinney at a conference last month in Houston sponsored by the consulting firm.
Daniel Yergin, Chairman of CERA, says the oil markets "are suffering acute whiplash" and that the price volatility since mid-last year is causing confusion and uncertainty. The International Energy Agency says a shortage of capacity was really at the center of the steep run-up in prices that ended last year. Although "speculation" may have played a role, it was really the fundamentals of supply and demand that drove the market. Strong growth from places such as China and India exploited years of industry underinvestment in both the upstream and downstream, constraining supplies. It expects a similar tightness could occur in just a few years after the global economy fully emerges from what appears to be a severe recession.
Permanent Reservoir Monitoring in Subsea Wells Attains New Level
Authors: Lovell John , Mackay Stuart 
Published: February 2015

Technology Update
Some material in this article has been previously published in papers SPE 116474 and 116476, presented at the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21-24 September. The figures for this article originally were published in paper SPE 116474.
Despite the credit crunch, worldwide subsea activity is still forecast to grow rapidly. In its recent 2009 subsea forecast, Infield Systems indicated that subsea drilling and completion expenditure will more than double to USD 80.5 billion between 2009 and 2013, from a total of USD 31.9 billion during the period from 2003 to 2007 (Infield 2009). Coupled with the increase in expenditure, Infield forecasts 3,222 subsea wells to be installed from 2009 through 2013, vs. 1,958 wells installed between 2004 and 2008. A large percentage of these wells will require sand control.
In market-share terms, Infield forecasts that Africa will remain the largest sector, representing 29% of the forecast capital expenditures between 2009 and 2013, followed by North America (25%), Latin America (19%), and Europe (13%). The remaining spending will be spread between Australasia, Asia, and the Middle East and Caspian region.
Despite this growth in the number of subsea wells, the expense of subsea well intervention often leads to insufficient reservoir information for accurately understanding reservoir connectivity, drainage, and flow assurance. This has led to an industry need for real-time data from sensors located on the sandface. For those wells requiring sand control, an additional constraint is that sandface sensors must be deployed on a separate completion run.

Reservoir-Monitoring Challenges in Dual-Stage Completions
Most wells with sand control use completion components that are deployed in multiple stages. This presents a challenge to achieving measurements from monitoring equipment located in the lowest stage of the completion because sensor power and data are required to be transferred across the junction between the lower and upper completion stages.
Consequently, reservoir monitoring in dual-stage completions has generally been limited to measurements of pressure and temperature near the production packer in the upper completion. These types of sensors cannot distinguish the downhole conditions of individual zones. Placing the sensors at the sandface, where the fluid enters, would take permanent monitoring to the next level because it enables operators to better understand the flow from each producing zone. This has now been achieved by an operator in southeast Asia who has deployed the Schlumberger WellWatcher Flux digital-sensor array system onto the screens of six openhole gravel packs in a subsea gas field. Data from those sensors has been transmitted to shore during cleanup, with the output used to make interpretations of permeability and cleanup efficiency for each producing zone.