bluuebunny/crossref_metadata_2025_split huggingface dataset:
Q&A with Tom Cochrane
Authors: Cochrane Tom , Donnelly John 
Published: February 2015

Tom Cochrane, SPE, is Executive Vice President of Oil & Gas Operations at Cano Petroleum, an independent producer with properties in the midcontinent region of the U.S. that specializes in increasing production from proven fields using enhanced-recovery methods. Before joining Cano, Cochrane spent more than 15 years as an engineer with ExxonMobil. His expertise includes CO2 and waterflooding, the coordination of injection and production logging, volumetric calculations, and drill well candidate identification. He also has extensive experience in production forecasts and reserves estimates.

Can you explain how the creation of Cano came about?
In my opinion, Cano Petroleum was inevitable. Jeff Johnson, our Chairman and Chief Executive Officer, spent several years pitching lenders and investors on his concept for a company that would focus exclusively on mature basins. It took a couple of years, but he ultimately did find investors who shared the vision of his enhanced-oil-recovery concept. These investors were able to look beyond the short periods of time when the price of oil was low and instead focus on the fundamentals of supply and demand. Jeff was one of the first to see this possibility and build a company based on these fundamentals.

What is Cano’s upstream expertise and its operating philosophy?
Cano has significant upstream expertise. My background includes 16 years of experience in secondary and tertiary recovery, including production and reservoir engineering, field maintenance, and production supervision. Production Coordinator John Lacik has 30 years of oilfield experience, including environmental expertise and extensive knowledge of chemical flooding. Cano also has had the great fortune to find outstanding, experienced production supervisors such as Jayme Wollison and Mike Parrish to take care of our assets. We also work with engineering and geologic consultants who have many decades of experience.
Our operating philosophy is to keep our people safe and uninjured and to protect the environment. We ensure that our decisions about equipment repairs and operating strategies appropriately position Cano to achieve the highest margins possible in the long term.
Cased-Hole Completions Without Perforating Eliminate Risks
Authors: JPT staff _ 
Published: February 2015

Perforating is a double-edged sword for well completions in unconsolidated formations. Perforations open conduits for hydrocarbon flow from the formation to the wellbore. But the perforating process can cause damage to the formation and result in excessive debris, posing operational risk and impairment to well productivity. As a result of a joint industry project (JIP) formed in 2002, a new technology has been developed and field tested that installs a liner and sand control completion in a single trip while eliminating explosive perforation charges and associated risks.
The Enterprise One-Trip Sand Control/Liner Hanger Completion system was developed by a JIP that included three major operators, a large service provider, and a small technology company. The fact that the technology was taken from concept to successful field-installation readiness in just 22 months illustrates that when operators and service/technology providers are committed to a common goal, technology uptake in the E&P business can proceed quickly.

Perforating Risk Factors
Perforating poses operational risks for operators in unconsolidated formations. Additionally, the perforating process can jeopardize well productivity by reducing the area open to flow and damaging the formation.
Generally, well productivity is directly related to the area of flow through a perforation tunnel. The greater the area of flow, the greater the well productivity. Entry-hole diameter and shot density impact flow area. Perforation debris in the perforation tunnel can block the available flow area, as can fractured and compacted zones and broken pieces of formation. The flow restriction caused by crushed zonal rock can also increase skin values, particularly over the life of the well.
Overview: Drilling Technology (February 2005)
Authors: Dupuis Dominique 
Published: February 2015

In the early 1900s, my grandmother ran to a field near the village of Le Bourget (future first Paris Airport) to see the trial of a pioneer aeroplane. Seventy years later, the flight time between Paris and New York was approximately 3 hours 30 minutes on the Concorde. At college, I worked with a slide rule; today, my laptop has many times the computing power of the NASA computer used when Neil Armstrong landed on the moon. Dupuis Such revolutions in drilling are not so quantifiable or spectacular; evolution improves the performance continuously. Even during crises, the drilled footage has remained constant. During the last 30 years, the number of bits manufactured has been reduced by a factor of 10, yet we now drill in water depths of 10,000 ft.
Greatest progress is driven mainly by the challenge of the spatial location of a new prospect and the obligation to improve recovery, hence the deepwater extended-reach multilaterals. The new challenge is to reach the deep buried reservoir with vertical depth of approximately 30,000 ft. The borehole pressure, the narrow mud windows, and high temperature trigger new technical development and lead to reconsidering monobore design as the well architecture. The expandable-casing technology is very promising. The second aspect is the change between engineering criteria and a probabilistic approach (for instance, applied to casing design where the probability of a situation or event is rendered acceptable) by improving safety procedures and equipment. This aspect also applies to underbalanced drilling with new procedures and devices.
Highlights of promising evolution include drilling-hydraulics optimization by revisiting classical drillpipe dimension and design to decrease the pressure losses (e.g., use of 4-in. drillpipe with streamline connections in a 6-in. hole); reconsideration of trajectory and drag and torque computations in directional drilling, taking into account drillstring stiff-ness, which could make future models more accurate; and future development of a low-cost 3D rotary-drilling system to improve onshore performance.
We regret that if drilling models improve, there is too little evolution and willingness to acquire drilling-parameter data, the weight on hook is deducted from the tension of the dead line for a difficult assessment of the systematic error caused by line reeving, rendering friction analysis difficult.
Evolution is steady, but has been rather spectacular when you look closely.
Additional Drilling Technology Technical Papers
Available at the SPE eLibrary: www.spe.org
SPE 89959 - The Trouble-Probability Plot: A New Measure of Drilling Maturity
SPE 91583 - Using Rotating Control Devices Safely in Today’s Managed-Pressure and Underbalanced-Drilling Operations
SPE 87217 - Increasing Effective-Fracture Gradients by Managing Wellbore Temperatures
Available at the OTC Library: www.otcnet.org
OTC 16564 - Casing Drilling With Retrievable Drilling Assemblies
Solution for Improved Riser-Tower- Systems Installability and Operability in Deep Water West of Africa
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 16630, "Bundle Hybrid Offset Riser: An Advanced Solution for Improved Riser-Tower-Systems Installability and Operability in Deep Water West of Africa," by Giovanni Chiesa, Saibos S.A.S.; Floriano Casola, Saipem S.A.; and Francois Regis Pionetti, Saibos S.A.S., prepared for the 2004 Offshore Technology Conference, Houston, 3-6 May.
Several riser-system configurations have been developed to assist hydrocarbon recovery from deepwater reservoirs. Vertical hybrid-riser systems were pro-posed for various deepwater developments west of Africa. The bundle-hybrid-offset-riser (BHOR) concept of a vertical hybrid riser uses bundle arrangements of multiple conduits to enhance flow assurance for delivering the production stream to the surface treatment facilities at production conditions anticipated during the field life. The bundle arrangement includes gas lift capability.

Introduction
Development of hydrocarbon resources in deep and ultradeep waters requires suitable gathering and transportation systems to deliver the production stream to the surface treatment facilities from remote subsea wells. Flow-assurance management becomes more important as reservoir exploitation moves toward deep water. The riser system is critical for flow-assurance management because of the following aspects.
- Significant temperature drop following depressurization along the riser conduits may affect the arrival temperature of the produced fluids at the surface receiving facilities.
- Gas lift injection capability boosts produced fluids to the surface, particularly when the gas content of the produced fluid is low; the gas lift stream must be delivered to the bottom of the riser conduits under certain pressure and flow-rate conditions that minimize the temperature drop along the riser length.
- Production conduits filled with wet gas following shutdown can lead to potential hydrate formation during restart, or produced fluids can enter the gas lift line through the injection orifice, potentially blocking the line in the event of low temperatures.
- Methanol-injection capability can eliminate hydrate on restart.
- Full depressurization of the flowline can dissipate a flowline blockage
Q&A with Jose Formigli
Authors: Formigli Jose , Donnelly John 
Published: February 2015

Brazil's goal has been to reach energy self-sufficiency early this year. Is that goal still attainable?
Our target is to reach self-sufficiency, on a sustainable basis, during 2006, when Petrobras' domestic oil production will reach an average of about 1.9 million BOPD.
What are Petrobras' growth targets for offshore and onshore oil and gas production?
In the recent revision of our Strategic Plan, we forecast production growth of 8.1% per year, from 1.76 million BOEPD in 2004 to 2.81 million BOEPD in 2010 (Fig. 1). This growth will come mainly from deepwater fields in the Campos and Espírito Santos basins.
The onshore oil production comes from mature basins, relying on an important existing infrastructure. Onshore findings can come on stream at a fast pace, requiring low capital expenditure, which compensates for the decline of the mature fields. The corporate pro-gram named Revitalization of Fields with High Degree of Exploitation is focused on the identification of economically feasible opportunities for increasing the production of oil and gas and/or increasing the ultimate recovery. The focus is not only on onshore brown-fields, but also on offshore fields beyond the production peak. As a result of these efforts, we expect that the 2010 onshore production of oil and gas will be kept at the same level of 293,000 BOEPD attained in 2004.
What new offshore production has recently come on line or will start up in the near future?
Many offshore production systems started up at the end of 2005 or are scheduled to start up throughout 2006:Peroa-Cangoa gas field, in the Espírito Santos basin, is beginning production of 2.5 million m3/D through a shallow-water fixed platform.Floating production, storage, and offloading vessel (FPSO) P-50, located at the Albacora Leste field, started up in November 2005, with a production capacity of 180,000 BOPD.FPSO P-34, located at the Jubarte field, is expected to start production of 60,000 BOPD during the first quarter of 2006.The Manati offshore gas field in Bahia has a capacity of 6 million m3/d through a fixed platform and will start production in the second quarter of 2006.Golfinho I, in the Espírito Santos basin, will produce 40°API oil and has production capacity of 100,000 BOPD. It is scheduled to come on stream in mid-2006.The deepwater Piranema field in the Sergipe-Alagoas basin is scheduled to produce 20,000 BOPD of light oil using the pioneer concept of a cylindrical floater production and storage system. It will start operation in the second semester of 2006.
Technology Tomorrow: Carbon, Hydrogen, and People
Authors: Rao Vikram 
Published: February 2015

Editor's note: This is the first installment of a new yearlong series designed to stimulate discussion in research and development. The Technology Tomorrow articles will be published every other month and vary in emphasis, covering topics as broad as R&D industry trends and as focused as improving reservoir recovery factors. This series is one of several actions being taken by the SPE R&D Advisory Committee to encourage R&D development and discussion. The target audience is the entire readership of JPT. We hope to create a forum that sparks discourse and ideas, including those ideas that may not be in the current mainstream of thought. Comments on the articles are welcome. Please send any questions, comments, or ideas to vik.rao@halliburton.com.
Two of the most pressing problems facing the oil and gas industry are the perceived shortages of oil and natural gas and an aging workforce combined with the inability to attract talent to the industry. The first is manifest in the price of oil worldwide, and that of gas in the consuming countries. Both of these are at unprecedented highs and, more importantly, are widely forecast to stay high for a number of years. Unlike the oil price shocks of the 1970s, this one is demand driven, and this time the world's workhorse producing fields are in the decline phase.
So, do we face a medium- to long-term prospect of shortages of oil, gas, and people? This article advances the belief—probably not. Energy molecules are plentiful; they are just in the wrong form or in the "wrong" place. Similarly, qualified personnel are available and not averse to working in the energy industry, they are just in places we do not source from enough. Much support can be offered for the first contention; the one regarding people relies on solid numbers and a dose of conjecture.

Unlocking the Potential
All energy-producing compounds comprise carbon (C) and hydrogen (H) in some proportion. Coal is at one end of the C/H spectrum, with the carbon-to-hydrogen ratio in excess of 8. At the other end is natural gas. Curiously, these two polar opposites are the principal sources of energy for electricity generation. The molecules in the middle are used for transportation and, for that purpose, need to be delivered in the form of light and middle distillates, gasoline, and diesel. Two unconventional sources of oil found in abundance are shale oil (more than a trillion bbl) and ultra heavy oil (also well over a trillion bbl). The former is in the form of kerogen, requiring thermal modification to yield useful oil, and the latter is a material that does not flow readily and, consequently, is difficult to produce and transport. It has C/H ratios in the vicinity of 8 and thus is many hydrogen atoms short of the needed light and middle distillates.
Management: Progress and Challenges for Health, Safety, and the Environment in Exploration and Production (February 2006)
Authors: Arscott Lyn 
Published: February 2015

Introduction
A computer-based survey was taken of the program committee members of the first Asia Pacific Conference on Health, Safety, and Environment (HSE) in Oil and Gas Exploration and Production, which was held in Kuala Lumpur during 19–21 September 2005. The committee members, experts in their fields, were asked to express their opinions on the progress of the industry on HSE issues over the past 5 years and the effort that the industry should make over the next 5 years. This was the second time this survey has been conducted. The first time was at the SPE Seventh International Conference on HSE held in Calgary during 29–31 March 2004, and the results were reported in the July 2004 issue of JPT.1 The Kuala Lumpur results and the Calgary results are presented in the tables below. It should be noted that informal surveys were taken of the program committee members of the previous six SPE international conferences on HSE starting in 1991, but they were not in the same format as the two conferences mentioned above, so a quantitative comparison is not possible.

Methodology
The committee members were asked to complete a web-based questionnaire with the following questions:How would you rate the progress made by the industry in the following subjects over the past 5 years (excellent, good, moderate, poor, very poor)?How would you rate the effort that the industry should make in the next 5 years (much more effort, more effort, same effort, less effort, much less effort)?How would you rate the effort regulators should make in the next 5 years?How would you rate the effort that nongovernmental organizations (NGOs) should make in the next 5 years?
The method of scoring and ranking is summarized in the appendix. A summary of the status of the industry programs is shown in Table 1, with the full results in Tables 2–4.
Overview: Drilling and Cementing Technology (February 2006)
Authors: Dupuis Dominique 
Published: February 2015

During 2005, the oil industry paradigm changed somewhat. The media highlighted doubt concerning world oil reserves expressed in time expectancy. Is it less than the sliding 40-year scenario? There are optimistic and pessimistic scenarios. During the year, demand and supply coincided. The oil prices increased drastically as a consequence of the growth of China, India, and other countries. On the other hand, environmental specialists have alarming forecasts with respect to the greenhouse effect and temperature increase because of CO2 accumulation. Initially, the capture of CO2 probably will lead to more wells being drilled. As a result of these contradictory parameters, the drilling industry has many challenges ahead to deal with instantaneous lack of oil and future complex developments.
The giant fields are reputed as discovered. Maybe the potential lies in some unexplored region (e.g., east Siberia), deep buried reservoirs (onshore and offshore), or better drainage of existing reservoirs improving the recovery factor to 65% or more.
To renew the reserves, the drilling community faces many challenges.
For deep reservoirs, in some instances ultradeep wells, those challenges lie in ultrahigh pressure, high temperature, and narrow mud-weight windows. Therefore, a new casing design (e.g., monobore) and new engineering and operation procedures will be required.
For enhancing the life of existing reservoirs, the technology of through-tubing completions opens new perspectives.
Cementing operations, often underevaluated, are of prime importance. Recent developments have led to a wider range of cement-slurry density, new well designs, and simplifying of operating procedures.
Coming back to basics, with respect to destruction of rock, let's dream: Why not a revolution using laser technology? Future generations of drillers will write case-history papers on laser-drilled wells. How soon—in 2050, 2030, maybe sooner?
Drilling and Cementing Technology additional reading available at the SPE eLibrary: www.spe.org
SPE 92194 "Maximizing Drill Rates With Real-Time Surveillance of Mechanical Specific Energy," by Fred E. Dupriest, SPE, ExxonMobil, et al.
SPE 95888 "Benchmarking Deep-Drilling Technologies," by S.W. Lambert, Schlumberger Consulting Services, et al.
SPE 96927 "Why Don't We Pump More Type I/II Lightweight Slurries?" by R.R. Myers, SPE, BJ Services Co.
Available at the OTC Library: www.otcnet.org
OTC 17459 "Drilling Underbalanced From a Floating Unit in a 1500-m-Water-Depth Exploratory Well: Planning, Equipment, and Rig Modifications," by A.C.V.M. Lage, Petrobras
Overview: Well Testing (February 2006)
Authors: Stratton Jay 
Published: February 2015

Careful well-test design applied intelligently to exploration and development situations is the reality check for information that many times can only be inferred from other reservoir-evaluation tools. With drilling rigs in short supply and day rates at historic high levels, smart application of well-test technology may reduce costs considerably by use of short-duration openhole wireline-test equipment. Commerciality can be determined quickly and rigs moved on to the next objective or well. In contrast, extended well tests, conceived to prove a commercial hydrocarbon accumulation, may provide enough data to validate a reservoir description and clear economic hurdles without drilling an additional well—important for time-critical decisions on adjacent leases.
Many times in the operating environment, a petroleum engineer may use well-test results to provide a reality check and economical data acquisition for geophysicists, production geologists, and simulation engineers on one end of the organization and production operations personnel pushed to maximize well rates on the other end. Careful well-test planning and analysis can satisfy both extremes. Reservoir-characterization professionals can validate reservoir boundaries, pressures, and the accuracy of production history. Production operations can maximize production confidently in a miscible-gas flood without going below minimum miscibility pressure and compromising recovery. A delicate balance can be maintained with little or no production loss, allowing responsible reservoir management while maximizing rates and ultimate recovery.
With oil prices hovering around U.S. –60/bbl, there has never been a larger incentive to optimize well testing in exploration, development, and production environments. This month's selections show how relatively conventional testing procedures, applied intelligently, can accelerate development decisions. Deconvolution of real-time reservoir performance is always going to be an attractive goal in well-test analysis to eliminate production loss from conventional pressure-transient analysis. Use of multiple analysis techniques can be complementary to other reservoir-characterization methods. Advances in intelligent completions, permanent data-acquisition systems, and flow-measurement technology continue to entice petroleum professionals into devising innovative techniques for advanced well-test analysis.
Well Testing additional reading available at the SPE eLibrary: http://www.spe.org/
SPE 96026 "Determination of Optimal Window Size in Pressure-Derivative Computation Using Frequency-Domain Constraints," by Y. Cheng, SPE, Texas A&M U., et al.
SPE 94436 "Time-Lapse Production Logging and the Concept of Flowing Units," by O.D. Cortez, SPE, Centrica Energy, et al.
SPE 94018 "Application of Buildup Transient-Pressure Analysis to Well-Deliverability Forecasting in Gas/Condensate Reservoirs Using Single-Phase and Two-Phase Pseudo pressures," by M. Bozorgzadeh, SPE, Imperial College, London, et al.