bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Integrated Decision-Management Process Shortens Time to First Gas
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 115251, "Reducing Time to First Gas: Lessons Learned in Expediting and Informing International Investment Chain Decisions," by Deborah D. Resley, SPE, and Christopher Reinsvold, SPE, Decision Strategies, originally prepared for the 2008 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 20-22 October. The paper has not been peer reviewed.
The monetization of gas, particularly in liquefied natural gas (LNG) projects, requires large capital investment in most links of the gas value chain from production to end use. Companies that invest in a single component of the value chain, such as nonintegrated gas producers, must understand the value of and risks inherent in every link in the chain, because gas will be priced in relation to its final point of sale. Final sale price as well as the effects of processing and capacity limitations ripple their way upstream to alter the timing, demand, and viability of the upstream investment.

Introduction
LNG projects are good examples of complex global gas-development projects with large capital-investment requirements. To build a commercial LNG project from gas production to point of final sale requires investment in and development of several capital projects. These linked or integrated projects serve to produce, treat, transport, and sell the gas in specific markets. These projects are joined in a value chain by at least 16 major commercial contracts, beginning with a production-sharing contract at the wellhead and ending with a gas-sales agreement in the end-use market. The entire set of investment decisions in the LNG chain can be driven by objectives such as the ability to book gas reserves by a certain date, optimizing the entire gas portfolio of assets, and in the case of companies with a portfolio of LNG assets, the potential for arbitrage and the ability to leverage and trade each LNG asset.
LNG projects now have even more complex business chains than 10 years ago, involving multiple investors in various parts of each chain. Successfully commercializing gas in integrated LNG projects and achieving acceptable returns requires numerous investment decisions. Building such a chain involves high-level coordination and integration of both technical and commercial processes, the option of reducing costs through increasing throughput, and leveraging economies of scale to reduce plant costs.
Perforating Techniques and Use of Cesium Formate Kill Pills To Maximize Productivity in HP/HT Gas Wells and Minimize HSE Risks
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 19242, "An Evaluation of Perforating Techniques and Use of Cesium Formate Kill Pills To Maximize Productivity in HP/HT Gas Wells and Minimize HSE Risks," by Alistair Roy, SPE, Allan Twynam and Jeff Parke, BP; Angus Morrison, Schlumberger; and John Downs, Cabot, prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed.
The BP-operated Rhum field is a North Sea high-pressure/high-temperature (HP/HT) lean-gas field. A key design requirement was to evaluate overbalance- and dynamic-underbalance-perforating techniques to optimize productivity while reducing the risk of producing hydrocarbons to surface during downhole operations. This case history focuses on available perforation techniques with the aim of matching or exceeding the flow performance achieved on the appraisal-well drillstem test (DST).

Introduction
The Rhum field is 45 km north of the Bruce field (Fig. 1). It has three subsea development wells tied back to the host Bruce production platform. The water depth is approximately 108 m. The field has several challenges.
Bottomhole temperature and pressure (BHP) were 300°F and 12,500 psi, respectively.
The lean-gas reservoir fluid leads to high surface pressures (&gt;10,000 psi).
The rock strength varies from 8,000 to 30,000 psi unconfined compressive strength (UCS).
Middle sour environment is expected with H2S levels of 10 to 20 ppm and CO2 levels between 4 and 8%.
Appraisal Well 3/29a-4 was spudded in August 2000, and testing was completed in February 2001. This well confirmed that the field was an HP (12,418 psia at 4745 m true vertical depth subsea), lean-gas discovery with approximately 1 Tcf of gas initially in place.

Completion Objectives
From the start of the project, a desired objective for the Rhum completions was to maintain at least one mechanical barrier and one fluid barrier while running the completion. This combination was essential risk mitigation for running completions in a subsea environment. Only two clear fluids were capable of delivering the required 1.9- to 2.2-specific-gravity (SG) brine weight: cesium formate and zinc bromide. The environmental risks of working with zinc bromide were deemed unacceptable; therefore, cesium formate was selected.
It was decided to evaluate whether cesium formate could be used during perforation to avoid the complicated rig ups and multiple runs required for deploying the required number of perforations by use of coiled tubing (CT) or electric line (E line).
Annual Drilling Conference Probes Technology Development and Lessons Learned
Authors: Donnelly John 
Published: February 2015

More than 1,500 industry professionals attended this year’s 3-day SPE/IADC Drilling Conference and Exhibition in Amsterdam, which placed special emphasis on the development and uptake of new technology. The annual event attracted representatives from more than 46 countries. It was the highest attendance for the conference location in Amsterdam, and it also set a record for exhibitors at the venue, with 48. Next year, the conference adds a new location, with the conference to take place in Miami during 21–23 February 2006.
Well-rounded and provocative plenary sessions touched on contemporary issues that affect drilling as well as other aspects of the upstream oil and gas industry. The sessions also featured an interactive component, in which audience members voted on the questions posed to the panel. The first plenary session—titled “New Technology Development: Who Tony Meggs Satish Pai Should Be Responsible?”—included moderator Toni Marszalek, Vice President, Schlumberger; Paul Ching, Director of E&P R&D, Shell Intl. E&P; Tony Meggs, Group Vice President, Technology, BP; Steven Newman, Vice President Performance and Technology, Transocean; Satish Pai, Vice President, Schlumberger Oilfield Technologies; and Kevin Lacy, Principal Adviser Well Engineering and Operations, ChevronTexaco.
Meggs offered an overview of R&D spending over the past decade, which saw a shift in spending from operators to service providers. Operators have reduced much unnecessary spending and, through consolidation, eliminated some duplication, leading to higher efficiency. But he acknowledged that the shift in R&D spending to service companies may have gone too far and that operators are now picking up the pace regarding expenditures. Pai called the amount now spent by the industry on R&D “worrying” because it has dropped significantly from the past. “It is now a big D and a small R,” with development spending far outstripping research, he said.
Interactive Log Simulation and Inversion on the Web
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90909, "Interactive Log Simulation and Inversion on the Web," by V. Polyakov, SPE, T. Habashy, R. Kocian, J. Pabon, and B. Anderson, SPE, Schlumberger-Doll Research, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
Log simulation is critical for understanding and interpreting logging-tool responses. Simulation helps the log analyst understand near-wellbore measurements in complex environments, particularly in anomalous situations. Simulated logs also can be used in “what-if” scenarios or as part of an iterative scheme to determine the formation’s geometry and material properties. A forward-modeling and inversion environment with a multitier Web-based architecture was developed to provide universal access from the user’s desktop, through a common Web browser, to the simulator engine running on a high-performance compute server.
Introduction
The essence of log interpretation is the solution of the inverse problem: determining formation parameters from logging data. This task becomes difficult when the logging environment departs from simple, well-understood geometries. Many tools are designed to make deep-reading measurements and, therefore, are susceptible to formation heterogeneities. The most com-mon environmental effects are formation dip, invasion of borehole fluids, and the influence of adjacent formations. Frequently, a combination of these effects can obscure the true formation properties (e.g., formation resistivity and porosity), making it necessary to construct a complex 3D model of the formation to obtain an accurate solution. The only way to validate these complex models is by tool-response simulation, or inversion.
Some logging tools (such as dual induction and dual laterolog) do not provide sufficient information to perform accurate inversion. Iterative forward modeling of what-if scenarios is used routinely in these cases. Iterative modeling simulates the exact tool response in a series of given formations. However, this process requires a high level of user interaction. The initial formation model must be constructed from log, core, and geological information, then updated manually. A solution is reached when a computed log matches the field log.
Automated inversion is more efficient because no interaction is required after the simulation is launched. During the past decade, the introduction of array measurements with greater information content has made it possible to use inversion in log interpretation routinely. Some modern tools record so much data that interpreting their response without the use of inversion presents a considerable challenge.
The interactive Web-based interface provides a convenient and universal user access to the forward-modeling and inversion software. Also, the Web-based-programming interface makes the simulator available as a library for other oil and gas applications.
Guest Editorial: Canadian Oil Sands - Myth and Reality
Authors: Tertzakian Peter 
Published: February 2015

Was M. King Hubbert, the famous American Earth scientist, really the first visionary to talk about peak oil? Indeed, many regard Hubbert as the Nostradamus of the oil industry, with his 1950s analytic work on peaking oil production part of any discussion about world oil supply today. But on the other side of the Atlantic Ocean, John Cadman was an oil oracle too, predating Hubbert by 30 years. Though Cadman's thoughts about the future of oil were more qualitative, we are witnessing his important prophecies today. In the end, Hubbert's numerical analysis and Cadman's astute foresights go hand in hand.
A geologist by training, Cadman eventually became Chairman of Anglo-Persian, the predecessor company to British Petroleum, which has evolved into today's BP. Accepting the Chairmanship of Anglo-Persian on 2 November 1927, Cadman said in his inaugural address, "Very many years must elapse before natural petroleum resources will be unable to meet the greater part of the world's requirements. Of course, the time will eventually come when the world may have to look for a great part of its supplies from secondary and synthetic sources."
Fast forward 80 years. Enough time has passed to have seen many of the world's prime hydrocarbon reservoirs mature. Big oil exploration has gradually migrated from the easy geographies of Pennsylvania and Texas to the deep offshore waters of the Gulf of Mexico. Internationally, megascale oil projects today are found in places such as offshore Africa, the offshore Arctic waters of Russia, or many other places that are at what I call the "ends of the Earth"—geographically extreme places where the oil is buried deep under water and rock. In addition, a lot of oil is buried under deep layers of authoritarianism, corruption, civil strife, and geopolitical intrigue.
On the demand side, the President of the United States has acknowledged that the United States is "addicted" to oil. But the addiction does not end at the U.S. border; the craving for oil is global. Using Cadman's phrase for consumption: "The greater part of the world's requirements" is now a thousand-barrel-a-second oil dependency that is growing relentlessly year after year.
So, the time has come. The world's requirement for more and more oil is taxing the industry's ability to supply it easily. We have finally reached Cadman's point of transition, where the world needs to look for a great part of its oil supplies from "secondary and synthetic sources." Where is this happening on a big scale?
Discussion and Reply to "Advances in Polymer Flooding and Alkaline/Surfactant/Polymer Processes as Developed and Applied in the People's Republic of China"
Authors: Seright R.S. , Chang H.L. , Zhang Z.Q. , Wang Q.M. , Xu Z.S. , Guo Z.D. , Sun H.Q. , Cao X.L. , Qi Q. 
Published: February 2015

In the February 2006 issue of JPT, H.L. Chang et al. reported on some of the pilot and commercial-scale field activities of polymer flooding and alkaline/surfactant/polymer (ASP) flooding that were performed in China (Chang et al. 2006). Unquestionably, polymer flooding and ASP flooding are proven processes, and China should be proud of their work in these areas. Unfortunately, the article also advocated a controversial technology [flooding with aqueous colloidal-dispersion gels (CDGs)] as being superior to polymer flooding. I submit that this claim is misleading and generally incorrect. CDGs [i.e., relatively low concentrations of partially hydrolyzed polyacrylamide (HPAM) crosslinked with aluminum citrate] should not be applied without carefully examining the purported science and engineering behind this process.
Chang et al. speculated that low-concentration aluminum citrate/HPAM microgels propagate through porous rock like superpolymer solutions. Specifically, they suggested that these CDG formulations penetrate deep into porous matrix reservoir rock and subsequently provide higher resistance factors (effective viscosities in porous media) and residual resistance factors (permeability-reduction factors) than comparable HPAM polymer solutions without cross-linker. However, independent results from three university research laboratories demonstrated conclusively that this assertion is not correct (see Seright 2006 and Wang et al. 2006 for details). Another assertion made in the February article (Conclusion 3 on page 87) is that "a large amount of CDG would preferentially enter the high-permeability or thief zones and divert polymer or water into medium- and low-permeability zones." This assertion contradicts basic calculations with Darcy's law (Seright 2006). Furthermore, the field evidence given to support CDG gels can readily be attributed to other, more plausible, factors. In many cases, questions arise whether the aluminum citrate had a positive effect on the field results. More details can be found in Seright 2006 and Wang et al. 2006.
Q&A with Kenneth E. Arnold, Senior Executive Vice President, AMEC Paragon
Authors: Arnold Kenneth E. , Donnelly John 
Published: February 2015

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

When and why did you join SPE?
I came to SPE rather late in life. I am a facilities engineer by background, and most of the time in my early career at Shell I associated SPE with drilling and production and reservoir engineering. But, on the other hand, I was aware that SPE existed, and I became aware that there was information being published in JPT on facilities-related topics, most of it probably associated with the Offshore Technology Conference. The other thing that I was aware of was that facilities engineers were treated almost like second-class citizens in the oil industry in those days. The emphasis in career development was on people who had downhole and drilling experience, rather than people who had project and surface experience. In those days, facilities were not very big or very expensive; they were a small part of the overall development cost. Therefore, it was easier to get ahead if you were a downhole specialist rather than a project specialist.
I got to thinking that, since my bosses belonged to SPE, it would be a good idea for me to belong as well. There was really no technical society for facilities engineers. There were other societies that you could belong to, but they were not really focused on providing the kind of information exchange that facilities engineers needed. It looked like the only logical place for facilities was within SPE.

What was your first involvement with the Society?
My first activity was as a technical editor, doing peer review of papers that were facilities-oriented. There were not that many of us who had the capability of reviewing these papers, so it started very slowly. In the early 1980s, Roger Hite, who was with Shell at the time, had done a quick study and determined that there were a lot of facilities engineers at Shell but none of them belonged to SPE. So SPE put together an ad hoc committee on facilities engineering to try to determine if this was something that SPE should worry about, and I served as Chairperson of that committee. We discovered that about 25% of the engineers within the oil companies represented on the committee were facilities engineers, so, basically, we were not providing much service to this group.
Adco ESP Pilot
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 101492, "Adco ESP Pilot," by H.A. Hashim, Adco, prepared for the 2006 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, 5–8 November.
Adco's experience with electrical submersible pumps (ESPs) in deep, high-temperature, and high-gas/oil-ratio (GOR) wells has been discouraging. To ensure that future ESP applications in Adco's mature fields are successful, a comprehensive review was conducted to determine the causes of the previous failures and recommend methods to improve current practices. A multidisciplinary team was created to plan and execute an ESP pilot project. The result of this effort was the successful installation and operation of ESPs in two of the field's oil wells.

Introduction
The field is in southeast Abu Dhabi and was discovered by a seismic survey conducted in 1959. Crude oil from the reservoir is 42°API with an 850-scf/STB GOR. The reservoir temperature is 250°F. The field has been waterflooded for more than 25 years, resulting in a long history of producing wells ceasing to flow when the water cut reaches 40 to 60%. The long-term solution is to put these wells on artificial lift (AL) such as gas lift (GL) or ESPs.
The slow increase in water cuts will change to a much more rapid increase upon fieldwide implementation of the first phase of AL scheduled in 2009. Although GL is seen as the preferred AL method for the field, ESPs could be used as a secondary method.
An initial step to the fieldwide AL implementation was to plan an ESP trial with the objectives of restoring production and accelerating data acquisition on well and reservoir performance at higher water cuts to refine field-development plans.
The wells selected for the ESP project were three oil producers that had ceased to flow because of a high water cut. Because of mechanical-integrity problems with one of the wells, only two ESPs were installed.

Adco ESP Review
Although ESP performance in water-production wells and shallow oil wells is impressive, performance in deep and high-temperature oil wells has been beleaguered by a number of premature failures. To ensure that future ESP applications in these fields are successful, a comprehensive review was conducted to determine the causes of the previous failures and incorporate the findings into new designs and procedures for the pilot tests.
After analysis of the past ESP experiences, the review team agreed that all past failures could have been prevented if attention had been paid to detail. The failures in the past were primarily the result of wellbore pollutants and debris; poor manufacturing, quality assurance, and quality control; and installation practices.
Dope-Free Connections: A North Sea Case Study
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 105851, "Dope-Free Tubular Connections, Through Research and Development to Field Trial and Implementation: A North Sea Case History," by H.B. Andersen, M.P. Hummer, SPE, and R.C. Engell, SPE, Mærsk Oil, and Lionel Verdillon and Arnaud Parde, Vallourec & Mannesmann Tubes, prepared for the 2007 SPE/IADC Drilling Conference, Amsterdam, 20–22 February.
After an initial development period, a final dope-free product was ready for testing. A waxy compound is applied directly on selected premium threads, serving as both storage and running dope, eliminating requirements for cleaning and redoping at the wellsite. The decision was made to perform a field test.

Introduction
Mærsk Oil operates offshore wells in the Danish sector of the North Sea, which are characterized by being long horizontal wells (5,000 to 20,000 ft) drilled in chalk reservoirs. The wells commonly are completed with 4 1/2- or 5 1/2-in. completions inside a 7-in. liner hung off in a 9 5/8-in. production casing set just above the reservoir. In some cases, the liners are cemented in place to provide zonal isolation.

Field Trial
For the field test, 230 joints of 7-in., 29-lbm/ft liner with premium dope-free tubular connections (DTCs) were acquired. All joints were equipped with standard open-ended driftable protectors. The 7-in. liner was selected for the test because it would have the least effect on final well performance if it turned out the DTCs did not perform as expected. The decision was made to use two wells, one of which had a cemented liner so the pressure integrity of the connections could be tested.

Manufacturing Trial Order
The 230 joints for the test were produced in February 2002. In the plant, the dope-free layer was applied on connections manually before mill makeup. As expected, no major difference was found at the coupling makeup stage when compared with standard American Petroleum Inst. (API) modified mill makeup. The 230 joints were shipped to the offloading facilities in Esbjerg, Denmark, where pipes were stored until shipped to the North Sea offshore rig in March 2002.

Rig Deck
The pipes were received at the rigsite bundled in slings. On the deck, they were laid out in one layer at a time. For the field trial, the protector design did not allow the pipe to be tallied with protectors installed; consequently, these were removed and the pipe was tallied. The pipe was drifted with the protectors reinstalled. Drifting the pipe with the protectors installed ensures that no pipe scale or other debris pollutes the box-end threads during drifting. Drifting pipe without DTCs normally is done before cleaning the thread so drift debris in the thread is not an issue.