bluuebunny/crossref_metadata_2025 huggingface dataset:
Hibernia Extended-Reach-Drilling and -Completion Record
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 92347, "Hibernia Record Well Breaks Extended-Reach-Drilling and -Completion Envelope," by Carsten C. Elsborg, SPE, Esso Norway, and Adrian K. Power and Paul C. Schuberth, SPE, ExxonMobil Canada, prepared for the 2005 SPE/IADC Drilling Conference, Amsterdam, 23-25 February.

In 2002, development began on the northernmost compartment of the Hibernia development project (Block A). To access these reserves, drilling and completing a 31,000-ft measured depth (MD) oil producer was proposed, with a horizontal departure and vertical depth that exceeded the industry extended-reach-drilling (ERD) limits. Successfully drilling this well required the application and extension of available technology. The project required a large monobore completion system. The trajectory required management of weak and unstable intervals across an extended 17,000-ft-MD intermediate section. To meet these challenges, existing local experiences were leveraged, and recognized international expertise was used to supplement existing practices.

Introduction

The Hibernia development project is in 265 ft of water, 200 miles offshore Newfoundland and Labrador, Canada’s easternmost province, in the Grand Banks region of the Atlantic Ocean. Reservoir access is provided by use of an iceberg-resistant gravity-based-structure (GBS) platform (Fig. 1) with 64 well slots. Two fully equipped and independent drilling rigs service the wells. Drilling was initiated from the structure in 1997. From the beginning, the project was envisioned as an ERD development that would extend the technology and experience limits as the platform matured.

The reservoir is a series of thick-layered sandstones separated by intermediate shales. It is subdivided into large compartments or blocks by a series of faults that run bidirectionally across the reservoir (Fig. 2). These faults are highly sealing in nature and, hence, form the independent subreservoirs or fault blocks that make up the larger reserves. In 2002, the operator began accessing Block A, the largest undeveloped reserves block in the project. The block also was the farthest from the platform (approximately 4.5 miles). At the time, several extended-reach wellbores had been drilled to more than 20,000 ft MD.

Careful evaluation was made of drilling a subsea-satellite well vs. use of ERD technologies and knowledge gained on similar Hibernia wellbores. The team recommended the ERD option to drill what would become Hibernia B-16 36 (OPA1), the longest well in the world at this true vertical depth (TVD). The reward for success would be significant from a cost-savings perspective if the incremental risks from a drilling and completion standpoint could be mitigated.
Strategic Direction for Reducing Fatal Oil and Gas Industry Incidents
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 94416, "Upstream Onshore Oil and Gas Fatalities: A Review of OSHA's Database and Strategic Direction for Reducing Fatal Incidents," by C.K. Curlee, SPE, Marathon Oil Co.; S.J. Broulliard, ConocoPhillips; M.L. Marshall, U.S. Dept. of Labor - Occupational Safety and Health Admin.; T.L. Knode, SPE, Halliburton; and S.L. Smith, Chevron Corp., prepared for the 2005 SPE/EPA/DOE Exploration and Production Environmental Conference, Galveston, Texas, 7-9 March.

According to the U.S. Dept. of Labor—Occupational Safety and Health Admin.(OSHA) database for the period 1997 through 2003, one fatality occurred every 10 days in the U.S. upstream oil and gas industry. These data were studied to determine trends and provide insights into the safety failures and to study potential interventions to eliminate the high frequency of fatal incidents. This review provides oil and gas industry operating managers, safety professionals, trade associations, and others a way to improve programs and set priorities for reducing onshore oilfield-related fatalities.

Introduction

Each year, the U.S. Bureau of Labor Statistics (BLS) releases a Census of Fatal Occupational Injuries (CFOI) report. These reports indicate that the mining sector, which includes the oil and gas extraction subsector (i.e., all upstream E&P activities), typically experiences one of the highest fatality rates of all major industries. In the BLS report of 2003 data, 34.5 fatalities occurred for every 100,000 workers in the oil and gas extraction subsector, or one fatality every 4.3 days. This fatality rate is more than 8.5 times the average for all U.S. industries.

An industry-review team (IRT) was formed, consisting of professionals representing operating companies, drilling and well-servicing companies, and industry trade associations, as well as OSHA. The IRT examined the OSHA fatality information, with emphasis on validating the OSHA database. Once the database information was understood, the IRT determined trends to provide insights into the safety failures associated with E&P-industry fatal incidents.
Q&A with J. Larry Nichols, CEO, Devon Energy
Authors: Nichols J. Larry , Donnelly John
Published: February 2015

How have recent high oil prices affected your E&P program?

Our capital budget has tripled over the past 5 years. Part of that has come from higher oil and gas prices, but part of that has been because we have been growing the size of the company. While oil and gas prices have had some impact, we recognize that prices are volatile, and we are not relying on them staying at their current elevated level.

How did last year's hurricanes in the Gulf of Mexico affect your operations?

We were affected some, but not as badly as a lot of other companies. We had three platforms that suffered damage—they actually sank—but they were not critical platforms. They were in the area of other platforms, and we just rearranged our production scheme without having to rebuild those platforms. We were affected by some third-party pipelines that resulted in about 80,000 BOPD being suspended for a period. We have restored all but 6,000 BOPD of that now.

You recently acquired Chief Holdings and have made major acquisitions in the past. What is Devon's philosophy regarding growing through acquisitions or through the drill bit? Does that philosophy change in a high-price environment?

We have always stated that we like both; it depends on the circumstances whether acquisitions are attractive. We certainly have done a lot of acquisitions since we went public in 1988. But because of high oil prices, they are now increasingly difficult. One of the things we have done with our acquisitions is that each time we have bought a company, we have turned around and sold the bottom part of our portfolio, resulting in an ever-increasing quality of our portfolio. It is now difficult to find transactions that are accreting in value and that improve the quality of our portfolio. Chief was one of those rare exceptions.

What is your outlook for oil and natural gas prices?

You have to start with oil because that has such an influence on gas prices. It involves huge political questions that are very difficult to answer. Obviously, the world supply of oil is tight, and in the countries where one could increase production, many of them are difficult to do business in. That is why oil is trading where it is now, because of the political uncertainty of the Middle East, Venezuela, now Bolivia, and Nigeria. Long-term, we think that oil in the area of U.S. $50–55/bbl is probably a reasonable number, but that is not to say that there might not be huge volatility both above and below that number.

Gas is also challenged. In the U.S., companies are denied access in many areas where they could expand production, which has resulted in the supply of natural gas being very tight. We had a mild winter last year, and that helped.
The CO2 Pilot at Lacq: An Integrated Oxycombustion CO2-Capture and -Storage Project
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 11737, "The CO2 Pilot at Lacq: An Integrated Oxycombustion CO2 Capture and Geological-Storage Project in the South West of France," by Nicolas Aimard, Marc Lescanne, Gerard Mouronval, and Claude Prebende, Total, originally prepared for the 2007 International Petroleum Technology Conference, Dubai, UAE, 4-6 December. The paper has not been peer reviewed.

In 2006, Total launched an integrated carbon-capture and -storage (CCS) project in southwest France. It entails the conversion of a steam boiler into an oxyfuel combustion unit, with oxy-gen being used for combustion rather than air to obtain a more-concentrated carbon dioxide (CO2) stream that is easier to capture. The pilot plant, which will produce some steam for use by other facilities, will emit up to 150,000 tons of CO2 over a 2-year period, which will be compressed and conveyed by pipeline to a depleted gas field, 8 miles away, where it will be injected into a deep carbonate reservoir. CO2 injection is scheduled to begin by the end of 2008.

Introduction

For decades to come, oil and gas will remain an energy source of choice. But oil and gas operators have to develop fields that require much more processing and energy while reducing greenhouse-gas emissions to mitigate climate-change consequences. Among the options, CCS is an important option for tackling greenhouse-gas emissions. While the worldwide CO2 atmospheric emission was approximately 30 billion tons in 2005, CO2 geological-storage capacity could be very significant: approximately 600 to 1,200 billion tons in depleted oil and gas fields, 3 to 200 billion tons in unmineable coal seams, and as much as 1,000 to 10,000 billion tons in deep saline formations. This represents 70 to 500 years of storage at current production rates.

Industry pilot plants are necessary to ensure that CCS technology will be reliable, energy efficient, accepted by the public, and commercially viable. At the end of 2006, Total launched an integrated CCS project in southwest France that entails the conversion of a steam boiler into an oxyfuel combustion unit, with oxygen being used for combustion rather than air to obtain a more-concentrated CO2 stream that is easier to capture. The pilot plant will produce steam for use by other facilities and will emit 150,000 tons of CO2 over a 2-year period at the Lacq facilities. The CO2 will be treated, com-pressed, and conveyed by pipeline to the depleted Rousse gas field 18 miles away to be injected into a deep carbon-ate reservoir (Fig. 1).
Overview: Seismic Applications (August 2002)
Authors: Labastie Alain
Published: February 2015

Overview - No abstract available.
Malampaya Deepwater Gas-to-Power Project
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 14041, "Malampaya Deepwater Gas-to-Power Project: Malampaya Subsea Development," by J. Seaver, Shell Philippines Exploration B.V., originally presented at the 2002 Offshore Technology Conference, Houston, 6-9 May.
CVAR-FPSO Concepts With Dry Trees in Ultradeep Water
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 14001, "Competitive CVAR-FPSO Concepts With Dry Trees in Ultradeep Water; Weathervaning CVAR-FPSO for Brazil and Indonesia vs. Nonweathervaning for West Africa," by Norihiko Okamoto, SPE, and Hiroaki Hirayama, Japan National Oil Corp.; Kozo Ishida, SPE, and Kazuhisa Otomo, Japan Drilling; and Makoto Nishigaki, Mitsubishi Heavy Industries, originally presented at the 2002 Offshore Technology Conference, Houston, 6-9 May.
Q&A with Michael Fleming, CEO, WellDynamics
Authors: Fleming Michael , Donnelly John
Published: February 2015

Q&A - No abstract available.
Supply Chain Logistics Require Attention
Authors: Bento Joe
Published: February 2015

Management - No abstract available.
Overview: Seismic Applications (August 2003)
Authors: Gibbons Kate
Published: February 2015

Overview - No abstract available.
Optimizing Well Construction: Full-Waveform Data From While-Drilling Seismic Measurements
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 79844, "Optimizing the Well Construction Process: Full-Waveform Data From While-Drilling Seismic Measurements in the South Caspian Sea," by Jakob B.U. Haldorsen, Cengiz Esmersoy, and Andrew Hawthorn, Schlumberger; Mary L. Krasovec, Massachusetts Inst. of Technology; Sue Raikes, Toby Harrold, and David N. Day, BP plc; and James D. Clippard, Shell E&P Technology Co., prepared for the 2003 SPE/IADC Drilling Conference, Amsterdam, 19-21 February.
Drillability Assessment in Deepwater Exploration
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 15295, "Drillability Assessment in Deepwater Exploration," by Martin L. Albertin, Stephan Petmecky, Charley Jay, and Pinky Vinson, BP, prepared for the 2003 Offshore Technology Conference, Houston, 5-8 May.
Overview: Cementing Technology (August 2003)
Authors: Benge Glen
Published: February 2015

Overview - No abstract available.
The Effect of Cement Heat of Hydration on Maximum Annular Temperature
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 77756, "The Effect of Cement Heat of Hydration on the Maximum Annular Temperature of Oil and Gas Wells," by R.L. Dillenbeck, SPE, T. Heinold, SPE, and M.J. Rogers, SPE, BJ Services Co., and I.G. Mombourquette, SPE, Promore Engineering Inc., prepared for the 2002 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 29 September-2 October.
The Quadruple Bottom Line (August 2004)
Authors: Baker Kate H.
Published: February 2015

President's column - No abstract available.
Overview: Offshore Completions (August 2004)
Authors: Cunha J.C.
Published: February 2015

Overview - No abstract available.
Overview: Intelligent Fields Technology (August 2006)
Authors: Gomersall Sam
Published: February 2015

Location, Location, Location

A key issue to be addressed by companies facing the challenge of the digital oil field is: What is the best location to store data? The key should be storing data to maximize the return on investment in digital data collection, and in today's world of the digital oil field, there is a lot you can do with data. The location of the data will determine its ultimate value to the organization.

The digital-oilfield step change is as significant as the introduction of PCs into the oil field or the introduction of effective internal networks and the Internet. Both technologies changed the types of data available, how the data are stored, and how security is managed. What does the next step change of the digital oil field require?

Today's challenge is to manage distributed and global organizations, involve internal and external experts, and collaborate effectively with partners. Data volumes have increased by orders of magnitude and will continue to do so with the increasing volumes of real-time data. The number of expert resources inside oil companies has generally decreased, increasing dependence on external experts and partner companies. At the same time, information and communications technology (ICT), including oil/gas software, has developed significantly.

However, the ICT philosophy and practices of most companies do not reflect this new reality of industry's need or ICT capability. Oil industry ICT practices are inhibiting effective implementation of the digital oil field.

Part of the solution for the digital oil field is to move data and applications outside our traditional organizational structures. Having data and applications on the network enables providing appropriate secured access for experts and collaboration partners and makes use of the available advances in ICT.

Maximizing the value of data and enabling the digital oil field will require significant change, which will include moving our data and applications onto the network. Data location will be critical.

Intelligent Fields Technology additional reading available at the SPE eLibrary: www.spe.org

SPE 99963 "Continuous Well-Production Flow Monitoring and Surveillance" by H. Poulisse, Shell Intl. E&P B.V., et al.

SPE 99243 "Integration of People, Process, and Technology for Right-Time Production Management and Optimization in Brunei Shell Petroleum" by S. AlKhadhuri, Brunei Shell Petroleum, et al.

SPE 99850 "ISIS—A Real-Time Information Pipeline" by J. Foot, BP plc., et al.

IPTC 10319 "Automatic Optimization of Infinite Variable Control Valves" by S.M. Elmsallati, SPE, Heriot-Watt U., et al.
How Processes Will Contribute to the Next Trillion Barrels
Authors: Miller Jeffrey A.
Published: February 2015

Guest editorial

When our industry talks about technology, the discussion quickly moves to game changers and specific events in which a new widget does something new. These widgets are generally successful but are usually applied to relatively narrow applications. While I absolutely agree that such innovations are extraordinarily important to our industry, I believe that the humble, unheralded technology of process innovation will provide an equally important contribution to how we produce the next trillion barrels of oil. Our ability to take broad areas of technology and to reliably and rapidly customize very specific wellbore solutions will become increasingly important to our industry.

In my job, I get to talk with clients all of the time, and I recently had the chance to listen to a group of successful operators discuss a resource play. The conversation quickly turned to how they planned to drill the asset, and I asked them about mud systems. They indicated that they planned to use oil mud, even though they believed water-based fluid would likely get the job done more efficiently. Why is this? The real reason was because the first well drilled successfully in this resource play was drilled with oil. This is an example of a situation where we are effectively doing what we have always done based on observation of a successful phenomenon.

We can rely on observable phenomena as long as all of the "right" drilling parameters somehow remain consistent. I see the challenge less as one of new technology development, but rather as one more closely aligned with how we reliably apply mass customization of technology (in this case, chemistry) to reliably customize broad areas of science to specific wellbore challenges. Nevertheless, it is the rare drilling fluid system that is simply pulled off the shelf, sent to a location, and run successfully without some level of customization—one exception being possibly the soap stick, and even that was only under specific conditions.

So, how do we effectively customize solutions on a large scale? First, we must understand why systems behave and perform the way they do at an elemental level. Next, we must execute stable processes that allow us to reliably investigate observed phenomena.

Efficient customization of technology is increasingly important; additionally, complexity and drilling envelopes are pushed to the technical limits of the industry's current capability. By integrating engineering tools into the customization process, it becomes possible to more efficiently and reliably distill broad technology systems down to a very specific and customized solution that maximizes the operator's wellbore value.
Comments (September 2002)
Authors: Donnelly John
Published: February 2015

Editor's column - No abstract available.
Mentor's Feminine Side
Authors: Sprunt Eve S.
Published: February 2015

Guest editorial - No abstract available.
Overview: Smart Wells (September 2002)
Authors: Stratton Jay
Published: February 2015

Overview - No abstract available.
Intelligent Well Technology in Mature Assets
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 71822, "Intelligent Well Technology in Mature Assets," by Navid Akram, Steve Hicking, Paul Blythe, Peter Kavanagh, and Paul Reijnen, Shell U.K. E&P Ltd., and Derek Mathieson, SPE, WellDynamics Intl. Ltd., originally presented at the 2001 Offshore Europe, Aberdeen, 4-7 September.
Reliable and Interventionless Intelligent Well Completion
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 14252, "Reliable and Completely Interventionless Intelligent Well Completion Technology: Application and Field Study," by D.E. Johnson, D.M. Turner, SPE, and D.J. Walker, SPE, OSCA Inc., and D. Harris and D. McDaniel, Kerr-McGee, originally presented at the 2002 Offshore Technology Conference, Houston, 6-9 May.
Lessons Learned From Frac Packs in the Campos Basin
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 73722, "Lessons Learned From a Hundred Frac Packs in the Campos Basin," by L.F. Neumann, SPE, and C.A. Pedroso, SPE, Petrobras, and L.M. Neto and R.C. Bezerra de Melo, SPE, BJ Services, originally presented at the 2002 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana,20-21 February.
Overview: Field Management (September 2002)
Authors: Marhubi Amran
Published: February 2015

Overview - No abstract available.
Permanent Fiber-Optic Monitoring at Northstar
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 76747, "Permanent Fiber-Optic Monitoring at Northstar: Pressure/Temperature System and Data Overview," by Tor K. Kragas, SPE, Weatherford Completion Systems, and Bill F. Turnbull, SPE, and Michael J. Francis, SPE, BP Exploration (Alaska), originally presented at the 2002 SPE Western Regional/AAPG Pacific Section Joint Meeting, Anchorage, Alaska, 20-22 May.
Geohazards: Are We Looking at Them the Right Way?
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 14106, "Geohazards: Are We Looking at Them the Right Way? View From Down Under," by Andy Lane and Alex Taylor, Woodside Energy Ltd., originally presented at the 2002 Offshore Technology Conference, Houston, 6-9 May.
Comments (September 2003)
Authors: Donnelly John
Published: February 2015

Editor's column - No abstract available.
Techbits (September 2003)
Authors: JPT staff _
Published: February 2015

Techbits - No abstract available.
Overview: Field Development (September 2003)
Authors: Pascolini Osvaldo
Published: February 2015

Overview - No abstract available.
Forecasting Development of Heavy-Oil Reserves in Ultradeep Waters
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 82019, "Forecasting the Development of Heavy-Oil Reserves in Ultradeep Waters Using Technological- Risk Models," by Saul B. Suslick, SPE, and Denis J. Schiozer, SPE, Unicamp; Francisco Nepomuceno, UERJ, Petrobras S/A; and Ricardo Furtado, SPE, Unicamp, prepared for the 2003 SPE Hydrocarbon Economics and Evaluation Symposium, Dallas, 5-8 April.
Al-Huwaisah Reservoir: Long Journey to Improved Oil Recovery
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 81461, "Al-Huwaisah Reservoir: The Long Journey to Improved Oil Recovery," by Mohammed Adil Al-Mugheiry, SPE, Guy Mueller, Marcel Braas, Thomas Materna, SPE, Huw Davies, Chia Fu Hsu, and John Keating, Petroleum Development Oman, prepared for the 2003 SPE 13th Middle East Oil Show and Conference, Bahrain, 5-8 April.
New One-Trip Multizone Frac-Pack System With Positive Positioning
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 78316, "New One-Trip Multizone Frac-Pack System With Positive Positioning," by E.H. Vickery, SPE, and C.F. Bayne, SPE, Baker Oil Tools, prepared for the 2002 SPE 13th European Petroleum Conference, Aberdeen, 29-31 October.
New Viscoelastic Surfactant Fluid Minimizes Pad Volumes and Viscosity
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 78317, "VES Fluid Allows Minimized Pad Volumes and Viscosity to Optimize Frac- Pack Geometry: Completion Type Evolution in Barbara Field, Central Adriatic Sea," by S.R. Mathis, SPE, Baker Oil Tools; Enzo Pitoni, SPE, Giuseppe Ripa, and Giovanni Ferrara, Eni SpA Agip; and Antonio Conte, SPE, and Mladen Ruzic, Baker Oil Tools, prepared for the 2002 SPE 13th European Petroleum Conference, Aberdeen, 29-31 October.
Overview: Gas Processing (September 2003)
Authors: Wichert Edward
Published: February 2015

Overview - No abstract available.
Planning New Developments in an Upstream Gas Business
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 81098, "A Process for Planning New Developments in an Upstream Gas Business," by Shivanand Maharaj, SPE, Eric Hennington, SPE, Michael Daniel, SPE, and I. Tenny Wibowo, BP Trinidad and Tobago LLC, prepared for the 2003 SPE Latin American and Caribbean Petroleum Engineering Conference, Portof- Spain, Trinidad, 27-30 April.
Sustainable Development in the Oil and Gas Industry (September 2003)
Authors: Arscott Lyn
Published: February 2015

HSE Horizons - This is an edited version of paper SPE 83062, which was prepared for presentation at the SPE/EPA/DOE Exploration and Production Environmental Conference held in San Antonio, Texas, 10-12 March 2003.
Guest Editorial: The Promise of New Reservoir- Monitoring Technologies
Authors: Warpinski Norm
Published: February 2015

Reservoir monitoring is a fast-developing area of production technology that has the objectives of measuring, controlling, and predicting the performance of the reservoir. From the measurement perspective, reservoir monitoring may include temperature, pressure, flow rate, composition measurements, periodic logging, 4D seismic, microseismic, deformation measurements, and a host of other possibilities. Most of the measurements made in reservoir monitoring today are wellbore-specific, targeting the conditions in a production or injection wellbore. On the other hand, technologies such as 4D seismic, microseismic, and surface deformation have the potential to image a volume of the reservoir away from wellbores, providing an understanding of how the reservoir is performing as a complete system. It is these imaging technologies that hold great promise for the future improvements in the understanding of overall reservoir performance. It is my opinion that as surface-deformation monitoring is better understood by the industry, there will be a trend toward its use over 4D seismic on many onshore fields because of its low cost, fast turnaround, and wide areal interrogation of the reservoir.

The first recorded instance of surface-deformation monitoring that I am aware of was associated with the disposal of low-level radioactive waste in cement fractures at Oak Ridge in the 1960s. The leveling-type measurements were relatively crude, but the fractures were shallow and wide, and the results were reasonably good. Today, surface-deformation measurements are quite sophisticated, using tiltmeters for precision measurements, interferometric synthetic aperture radar (InSAR) for large-scale reconnaissance, and global positioning systems (GPS) for a host of intermediate and combined applications. Currently, these types of measurements are limited to onshore applications, but subsea measurements are possible in some cases.

Tiltmeters measure the horizontal gradient of the vertical displacement with great precision (up to one nanoradian), and an array of tiltmeters properly situated over a reservoir can be used to extract the surface deformation that is taking place because of processes occurring deep underground. These tools are sensitive enough to pick up Earth tides caused by the moon's pull on the Earth's crust over time. Results can be processed to calculate reservoir-level volumetric changes. GPS and InSAR, on the other hand, measure the actual displacement of the surface, but with considerably less precision. InSAR has the least resolution of the techniques, but it has great appeal for the large areal extent that can be covered and minimal (often zero) ground equipment. Being able to identify subcentimeter ground deformation over hundreds of square kilometers for a few thousand dollars has great appeal.
Overview: Wellbore Integrity, Sand Management, and Frac Pack (September 2007)
Authors: Goodman Harvey E.
Published: February 2015

Reviewing papers for this month's Wellbore Integrity, Sand Management, and Frac Pack feature finds our industry hard at work to improve understanding of the complexities of formation failure in the near-wellbore region. This work involves hole-failure modeling and mitigation in the shale sections through the overburden and in the reservoir, with a strong focus on solids-production risk.

On the theoretical side, shale-instability mechanisms from purely mechanical failure to accounting for chemical and thermal effects are being modeled and consequences are being addressed in the well-engineering plan. The complexity of predicting wellbore-stability behavior is daunting when the "wish list" of model-prediction input-data requirements is considered. Even so, these comprehensive theoretical approaches to hole-failure modeling provide critical insight to complex formation-failure processes that then is used to underpin the shortcuts we are often forced to take in hole-instability prediction because of a lack of data. Furthermore, this research provides guidance in determining the measurements operators should invest in (e.g., cores, logs, and well tests) to achieve the desired hole-instability-prediction uncertainty range for a specified well plan.

This paper review also finds exploration- and development-prospect environments to be increasingly complex. Deepwater subsalt plays are becoming more common. The trend in technology development and application for these harsh and correspondingly expensive projects finds extensive early-project predrill performance modeling the norm, not the exception. However, even with the most comprehensive predrill model prediction, uncertainty still is present. Often, the gap between predicted hole instability and reservoir-sand production vs. field-performance results is great, leading to heavy R&D on tools and techniques that can preserve hole integrity while ensuring that the hole size needed to install sand-control completions, including frac packs, is achieved.

Wellbore Integrity, Sand Management, and Frac Pack additional reading available at the SPE eLibrary: www.spe.org

SPE 100202 "Maintaining the Stability of Deviated and Horizontal Wells: Effects of Mechanical, Chemical, and Thermal Phenomena on Well Designs" by Jianguo Zhang, SPE, Baker Atlas and Baker Hughes Drilling Fluids, et al.

SPE 102626 "Remediation of Production Loss Due to Proppant Flowback in Existing Wellbores" by Philip D. Nguyen, SPE, Halliburton, et al.

SPE 108241 "Sustainable Deployment of Geomechanics Technology to Reducing Well Construction Costs" by Fersheed K. Mody, SPE, Shell, et al.
Technology Focus: Completions Today (September 2008)
Authors: Horvat Damir
Published: February 2015

Technology Focus

I am not here to discuss the process of detailing the optimum completion design. However, I do believe that there is no single parameter to serve as the "rule of thumb" to judge well-completion designs for the life of the field.

Earlier this year, I attended the first SPE Unconventional Reservoirs Conference at Keystone Resort and Conference Center, in Keystone, Colorado. Afterward, I attended a workshop presented by Shell Energy Canada and Calgary Research Centre. Both presentations highlighted the emerging and applied technologies in use worldwide for recovery of unconventional hydrocarbon resources.

As with all conferences, I had the opportunity to engage in discussion with many world experts from various operating/service companies and academia. After thorough discussions with all parties, I have reviewed an abundant reference list on well completions that use sonic stimulation. Many were anecdotal. Some may argue this was because of the nature of the studies, in which improved production was observed after some coincidental event that may or may not have been responsible for incremental hydrocarbon production. In my opinion, all studies should be scientific, not anecdotal, so long as the sonic stimulation was applied with the intent of enhanced hydrocarbon production.

Thorough discussions, backed with research on this subject, ensure that certain aspects of the well's operation, such as safety, availability, and efficient use of equipment inventory, are not overlooked. Many readers will agree that not all well completions achieve this objective. I have found that many unconventional-reservoir failures may not be a function of the manner in which they were designed, but may be simply the result of purely unknown complex reservoir-related mechanisms.

I advocate that operating companies use advanced diagnostic procedures that match and predict performance to estimate reservoir potential, well deliverability, and completion efficiency accurately. I believe in focusing on some of the best practices, such as economics (i.e., net present value), as the main driver. Hence, alternative completions such as sonic stimulation may be a viable alternative to reduce workover costs and improve ultimate hydrocarbon recovery.

Completions Today additional reading available at the SPE eLibrary: www.spe.org

SPE 113106 • "Optimization of Completion Interval To Minimize Water Coning" by M. Tabatabaei, SPE, University of Louisiana at Lafayette, et al.

SPE 113670 • "Through-Tubing Inflatable Technology Deployed on a Downhole-Tractor System Provides Real-Time Cost Savings" by Graeme M. Kelbie, SPE, Baker Oil Tools, et al.

SPE 108656 • "Harsh-Environment HP/HT Gas-Condensate Production Cleanup Experiences—Kristin Field" by Arild Fosså, Expro, et al.

Additional reading available at OnePetro: www.onepetro.org

OTC 19341 • "Expandable Screens: Optimized Horizontal Gas Production Through Collaboration" by Alejandro Lopez Lara, Pemex, et al.
Q&A with Nader Sultan
Authors: Sultan Nader , Donnelly John
Published: February 2015

Q&A - No abstract available.
Vertical Annular Separation and Pumping System
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 14003, "VASPS Installation and Operation at Campos Basin," by O.R. do Vale and J.E. Garcia, Petrobras S.A., and M. Villa, ENI SpA, originally presented at the 2002 Offshore Technology Conference, Houston, 6-9 May.
Per forating System Selection for Optimum Inflow Per formance
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 73762, "Perforating System Selection for Optimum Well Inflow Performance," by Kent Folse, SPE and Melissa Allin, Halliburton Energy Services; Chris Chow, SPE, ProDuce Consulting; and John Hardesty, Jet Research Center, originally presented at the 2002 SPE International Symposium and Exhibition on Formation Damage, Lafayette, Louisiana, 20-21 February.
Effect of Capillary Pressure, Salinity, and Aging on Wettability Alteration
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 75189, "Effect of Capillary Pressure, Salinity, and Aging on Wettability Alteration in Sandstones and Limestones," by Sruti Chattopadhyay, U. of Connecticut at Storrs, and Vivek Jain, SPE, and M.M. Sharma, SPE, U. of Texas at Austin, originally presented at the 2002 SPE/DOE Improved Oil Recovery Symposium, Tulsa, 13-17 April.
Turn Down the Burner: Heat Management in the Midway-Sunset Field
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 76726, "Turn Down the Burner: Impact of Heat Management on the Potter Reservoir, MWSS Field, California," by J.H. Fram, SPE, W.H. Dailey, SPE, and C.J. Walker, SPE, ChevronTexaco, originally presented at the 2002 SPE Western Regional/AAPG Pacific Section Joint Meeting, Anchorage, 20-22 May.
Acid-Treatment Effects on Openhole Stability in Limestone
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 77776, "Stability of an Openhole Completed in a Limestone Reservoir With and Without Acid Treatments," by Nobuo Morita, SPE, Tomoki Doi, and Takanori Kinoshita, Waseda U., originally presented at the 2002 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 29 September-2 October.
The Quadruple Bottom Line (October 2003)
Authors: Baker Kate H.
Published: February 2015

President's column - No abstract available.
Techbits (October 2003)
Authors: JPT staff _
Published: February 2015

Techbits - No abstract available.
Overview: Completions Today (October 2003)
Authors: Grigsby Tommy
Published: February 2015

Overview - No abstract available.
Reliability Assurance: Managing the Growth of Intelligent-Completion Technology
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 84327, "Reliability Assurance: Managing the Growth of Intelligent- Completion Technology," by Derek Mathieson, SPE, John Rogers, SPE, Shashidhar Rajagopalan, SPE, and Robert McManus, WellDynamics, prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
Compaction, Subsidence, and Associated Casing-Damage Assessment for Matagorda Island 623
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 84553, "Compaction, Subsidence, and Associated Casing- Damage and Well-Failure Assessment for the Gulf of Mexico Shelf Matagorda Island 623 Field," by X. Li, SPE, and F.L. Mitchum, SPE, BP plc; M. Bruno, SPE, Terralog Technologies USA Inc.; and P.D. Pattillo, SPE, and S.M. Willson, SPE, BP plc, prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
Fractured-Reservoir Recovery Factors: Lessons From 100 Fields
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 84590, "Controls on Recovery Factor in Fractured Reservoirs: Lessons Learned From 100 Fractured Fields," by Jack Allan, SPE, and S. Qing Sun, SPE, C&C Reservoirs Inc., prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
Downhole Measurement of Methane Content and GOR
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 81481, "Downhole Measurement of Methane Content and GOR in Formation Fluid Samples," by C. Dong, SPE, P.S. Hegeman, SPE, and A. Carnegie, SPE, Schlumberger, and H. Elshahawi, SPE, Shell, prepared for the 2003 SPE Middle East Oil Show, Bahrain, 9-12 June.
Comments (October 2004)
Authors: Donnelly John
Published: February 2015

Editor's column - No abstract available.
FPSO Solutions for 10,000-ft GOM Field Development
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 17200, "DeepStar - FPSO Solutions for 10,000-ft GOM Field Development," by J.E. Chitwood, Chitwood Engineers, and S. Hanrahan and G. Adhia, Chevron, prepared for the 2005 Offshore Technology Conference, Houston, 2-5 May. Copyright 2005 Offshore Technology Conference. Reproduced by permission.

DeepStar has evaluated new and emerging technologies for developing small standalone (marginal) fields in 10,000 ft of water in the U.S. Gulf of Mexico (GOM). These studies identified viable field-development scenarios that improve field economics. Further, the studies identified knowledge gaps requiring further investment before these development systems are ready for field application. This paper describes the evaluation process and uses floating production, storage, and offloading (FPSO) vessel development alternatives to illustrate the identification of specific knowledge gaps for FPSOs in 10,000-ft water depths.

Introduction

Deepwater fields like Thunderhorse are being developed in water depths approaching 6,000 ft in the GOM, and discoveries have been made in water depths to 10,000 ft, with many intermediate-water-depth discoveries. A life-cycle economic model was prepared for alternatives considered viable by the technical committee. Where technology was extended or new technology assumed available, an estimated commercial cost was used. The realistic input yielded a mature concept comparison in which the field-development alternatives were compared on an equivalent basis. The most promising development scenarios could then be identified. Evaluation criteria included the following.

- Projected economic performance.

- Schedule through project qualification.

- Cost of the necessary technologies through project qualification.

Four surface-facility scenarios were studied.

- Semisubmersible—provides lowest motion solution.

- Spar—features low motion and dry trees.

- Tension-leg platform—requires new ten-don technologies for 10,000-ft water depths.

- FPSOs—use a gas-export pipeline and an oil shuttle tanker.

When extending these surface facilities to 10,000 ft, the following critical aspects must be understood fully.

- Station-keeping method.

- Riser system.

- Surface facility.

- How all these items interrelate and operate as an integrated unit through all phases of operation (i.e., design, construction, installation, normal production, storm conditions).

This understanding must be further communicated to the regulatory and classification agencies to obtain approvals. FPSO arrangements included the following.

- Permanently moored weathervaning FPSOs.

- Dynamically positioned (DP) FPSOs.
Possible Existence of Deep-Seated Oil Deposits on Gulf Coast
Authors: Lucas Anthony F.
Published: February 2015

Editor's Note: Originally published in AIME Transactions, this paper, which is heavily excerpted here, discusses the possibility of oil lying beneath salt domes along the US Gulf Coast.

The discovery of oil in 1901 on the Spindletop dome, Texas, inaugurated a new industry on the Gulf Coast, an industry which has grown with the discovery of successive fields, until today it engages the services of thousands of workers and employs enormous capital. New fields are being discovered from time to time and doubtless some still remain to be found, though of late years, discoveries have become more infrequent. Nowadays, several hundred dry holes are drilled each year in a fruitless and blind effort to discover new fields, for as yet geologic science has developed no effectual method of locating the coastal oil deposits in advance of drilling.

Moreover, despite the occasional discovery of new fields, the total production of the Gulf Coast is today no greater than it was in 1906, for the added production of the new fields has been offset by the rapid decline and more or less complete exhaustion of some of the older ones. Careful geologic work within the fields has in some cases increased the production temporarily, but has developed no really new supplies. The Gulf Coast oil industry seems to have passed its period of greatest expansion and to be declining at a fairly steady rate, and this condition is naturally viewed with alarm by the more far-sighted operators.

In my opinion, the time has come for the adoption of radical and aggressive methods of prospecting; and a fraction of the money wasted yearly in drilling shallow wells in hopeless locations might well be devoted to this purpose. Many facts lead me to believe that all the salt-dome oil has had a common origin; that it has migrated up from considerable depth along lines of structural weakness; and that a deep well, properly located, stands an excellent chance of discovering the parent reservoir and thus of developing new and probably great supplies.

All of the oil produced in the coastal region of Texas and Louisiana is probably associated with salt domes, though in Goose Creek, Edgerly, and one or two other fields no salt has yet been actually penetrated. As a result of the innumerable wells that have been drilled on the various domes, it is now known that a typical salt dome consists of a very thick mass of pretty pure rock salt, generally almost flat-topped, but sloping abruptly away from the rim on every side. The flat top of the salt is generally covered by rock 25 ft to several hundred feet thick, consisting chiefly of limestone, dolomite, anhydrite, or gypsum, with generally more or less sulfur. The sediments above the salt are slightly domed and those on the sides of the salt mass generally slope at angles of 30 to 60°, and in some fields at even greater angles. These sediments consist of sand, gravel, shale, and gumbo, arranged in beds so lenticular and irregular that they can seldom be correlated from one well to another.
People Are the Thread That Hold This Industry Together
Authors: Percival Iain
Published: February 2015

It is an honor to reflect on the changes I have observed in the business since I joined it (and SPE in Dallas while backpacking around the US) in 1973. So much in the oil and gas industry has changed since the summer of 1973, and then again, in some areas, it has not. For me, one constant in the business has been the people. However, the composition of the global workforce and the way people actually work has changed dramatically. Consequently, if you will bear with me, I will share with you my perspective on people in the business.

I entered the industry at the time of the hegemony of the "Seven Sister" international oil companies (Shell, BP, Exxon, Mobil, Texaco, Socal, and Gulf) staffed primarily by petrotechnical staff from Europe and North America. Today, only four of the original sisters remain as independent companies, and, according to an article in the Financial Times earlier this year, the "new seven sisters" are Saudi Aramco, Gazprom, China National Petroleum Corporation, the National Iranian Oil Company, Petroleos de Venezuela, Petrobras, and Petronas, staffed to large measure with national Earth scientists and engineers educated in local (national) universities.

I am struck by the progress made by a number of countries in growing successful and powerful national oil companies (NOCs). A case in point is in Malaysia with Petronas. This year is the 33rd anniversary of the founding of the company, exactly the length of time I spent working for Shell. I had many dealings with Petronas in the early 1980s while working for Shell in east Malaysia. At the time, its prime (but not only) responsibility was to oversee the work of the production-sharing contractors such as Shell. The company had modest staff numbers and modest premises but not so modest ambitions! Today Petronas is a truly integrated oil and gas company with a global reach, a workforce in excess of 30,000, present in more than 30 countries, and based in a building of "world wonder" proportions—the twin towers in Kuala Lumpur, one of the world's tallest buildings.

Many of us who have worked in the business over the past 30-odd years can take a genuine measure of satisfaction in our contributions to the development of the national staff who built these companies. Whether as members of operating or service companies, we have helped train and coach national staff and as such have contributed to in-country expertise. In the case of Malaysia, Oman, and Brunei, I can name individuals in senior positions whom I have personally encouraged and coached, and whom I now count as valued friends or acquaintances.