bluuebunny/crossref_metadata_2025 huggingface dataset:
MA D6: A Fast-Track Deepwater Project
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 20174, ’MA D6 - Going Beyond the Limits of Deep Water Fast Track Projects,’ by Georges Michel, Willy Gauttier, and Pierre Savy, Technip, originally prepared for the 2009 Offshore Technology Conference, Houston, 4-7 May. The paper has not been peer reviewed.

The MA D6 field-development project in 1100 m of water is the first deepwater development on the east coast of India. The MA D6 project has been one of the fastest deepwater projects of its size involving a large amount of technical content in a location with minimal established infrastructure. The full-length paper describes the technical aspects of the project and the resulting designs that were selected, and it outlines the logistical issues associated with this first deepwater and fast-track project in the region.  

Subsea System Architecture

The MA D6 field is in the KG D6 Block 60 km from the east coast of India and is exposed to the eastern monsoon from April until September and to cyclones in the following months. This limits the safe and efficient operations of offshore construction vessels to a window extending from December to April.

The occurrence of cyclones led the operator to select a floating production, storage, and offloading (FPSO) vessel equipped with a disconnectable turret buoy that required a riser system designed for both connected- and disconnected-turret-buoy situations. The limited working window caused the project installation to be split into two phases: one before the monsoon season of 2008 to allow first oil on arrival of the FPSO and the second one the following year for the full production system. However, the engineering design of the whole riser system was needed at the early stage of the project to address all the interferences between the various risers during installation and operations and to define all the riser equipment in a pliant-wave configuration (Fig. 1), such as buoyancy modules, riser-anchoring piles, and tethers and clamps.

The field production system is based on the production of six wells through a production manifold, the injection of part of the produced gas into the reservoir by a satellite well, and the export of the gas to the future KG D6 gas-development field though a gas-export manifold (GEM).

The four 8-in.-inside-diameter (ID) flexible production risers connect the FPSO to the production manifold, the four 8-in.-ID gas-export flexible risers connect the FPSO to the GEM, and the gas-injection well is connected directly to the FPSO with a 6-in.-ID flexible riser/flowline. Each subsea tree is linked to the production manifold with 6-in.-ID flexible flowlines/jumpers, and control of all the subsea structures is achieved by a dynamic-umbilical connection between the FPSO and the production manifold and with static umbilical jumpers connecting the production manifold to the seven subsea trees and the GEM.
Presalt Santos Basin - Extended Well Test and Production Pilot in the Tupi Area: The Planning Phase
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 19886, ’Presalt Santos Basin - Extended Well Test and Production Pilot in the Tupi Area: The Planning Phase,’ by Celia M.F. Nakano, Antonio C.C. Pinto, SPE, Jose L. Marcusso, and Kazuioshi Minami, SPE, Petrobras, prepared for the 2009 Offshore Technology Conference, Houston, 4-7 May.

Petrobras is assessing the potential of the Santos basin presalt reservoirs offshore Brazil. Three integrated ultrafast-track projects were planned to start production of the giant presalt reservoirs in an area known as Tupi. The objective of the three projects is to obtain relevant reservoir and production data to support the design phase of the remaining production units of the full-field development. The main technical challenges addressed include drilling complex wells, use of intelligent completions, qualifying ultradeepwater risers, establishing flow assurance through long subsea flowlines, and CO2 capture and sequestration.  

Introduction

The Tupi area is in the central portion of the Santos basin, approximately 290 km offshore Rio de Janeiro State, at water depths of approximately 2200 m. The first well drilled in the block was Well RJS-628, completed in August 2006. The well was designed to test the carbonate section of an Aptian reservoir. It found a primary hydrocarbon-bearing reservoir in carbonate having microbial origin, named the SAG reservoir. A secondary microbialite reservoir, named the RIFT reservoir, also was found. Both reservoirs are below a thick regional layer of salt that occurs in this portion of the basin. Therefore, these reservoirs were classified as presalt reservoirs. The well was tested and produced after an acid stimulation. The choke-constrained production rates were 378 m3/d of 28°API crude oil with a gas/oil ratio (GOR) of approximately 220 m3/m3.

To verify the continuity of the SAG reservoir to the south, Extension Well 3-RJS-646 was drilled in July 2007, 10 km from the wildcat. The well, in the Tupi Sul area, confirmed expectations of the SAG and RIFT carbonate oil reservoirs, and reservoir characteristics were better than those of the previous well. Another oil-bearing carbonate reservoir, the Coquina reservoir, also was found.  The well tested a choked rate of 445 m3/d of 27°API oil from the SAG reservoir with a GOR of 230 m3/m3. Because of logistics constraints, the deeper reservoirs could not be tested. The reservoir area was covered completely by 3D-seismic data. High-resolution seismic is being acquired in the Tupi area.
Technology Focus: Offshore Facilities (February 2011)
Authors: Ball Ian G.
Published: February 2015

Technology Focus

Our industry continues to make great progress in creating and qualifying new technical solutions to meet the need for cost-effective offshore oil-/gas-production facilities in evermore-challenging environments. In last year’s Offshore Facilities Focus, we reviewed some of the more-prominent recent examples, and in this edition we cover some further updates on progress. There is, however, a particular theme running through these latest examples, which are perhaps worthy of some special attention.

The E&P industry is renowned for its ability to generate impressive technical solutions for just about any well-defined offshore challenge it may face. In my experience, it has been less able to demonstrate a similar global consistency across cultures in the manner in which the supplier and the client go about achieving the potential of the technology in practice.

In one recent firsthand exposure, there even appeared to be a deliberate mind-set of challenge and contractual standoff from the outset between the two parties. The intended aim was to bring about rapid execution at lowest possible cost. It is questionable whether this approach ever can be sustainable beyond the particular project in question, and whether either party’s best interests can thereby be served in practice.

What shines through in the examples covered in the following pages is how a purposefully collaborative approach can make a positive difference to the benefits for both parties. These benefits often can be enhanced further by establishing a broader constructive and collaborative framework with a wider group of stakeholders that typically can include installation contractors and classification/certification agencies.

The success of individual-project collaborations leads to a sustainable contracting environment into the future. Also, it can, in some cases, lead to global frame agreements, which can enable both parties to harvest expanded economic and schedule benefits from building on the culture of mutual respect and aligned objectives. I hope you enjoy these case studies as much as I have.

Offshore Facilities additional reading available at OnePetro: www.onepetro.org.

OTC 20762 “Demonstrating the Feasibility of Steel Catenary Risers From a Cylindrical FPSO in Harsh Deepwater Locations” by Jan V. Aarsnes, Sevan Marine ASA, et al.

OTC 20506 “Deepwater-Pipeline and -Riser Installation by the Reel-Lay Method” by S.N. Smith, Subsea 7, et al.

OTC 21024 “Top-Tensioned-Riser Systems for a New Floater Type” by David L. Garrett, Stress Engineering Services, et al.
Water and Data and Wells - Three Keys To E&P'S Future
Authors: Rassenfoss Stephen
Published: February 2015

Higher energy prices have pushed exploration and production (E&P) into difficult places with enormous potential, from ultradeepwater fields offshore to unconventional reservoirs onshore. With every advance, though, new problems emerge.
New Reserves and Resources Guidelines Document Available
Authors: Purewal Satinder
Published: February 2015

Management

In November, the SPE Oil and Gas Reserves Committee (OGRC) published Guidelines for the Application of the Petroleum Resources Management System (PRMS). The guidelines, available at http://www.spe.org/industry/docs/PRMS_Guidelines_Nov2011.pdf, provide information and examples on the use of PRMS in the classification of oil and gas reserves and resources.

The new guidelines replace the 2001 Guidelines for the Evaluation of Petroleum Reserves and Resources. New chapters include “Estimation of Petroleum Resources Using Deterministic Procedures” and “Unconventional Resources.” Other chapters were updated and expanded to reflect current technology and enhanced with examples. The intent of the guidelines is not to provide a comprehensive document that covers all aspects of reserves calculations, but to serve as a useful reference tool for reservoir engineering and reserves evaluation professionals around the world.

SPE has been at the forefront in developing common standards for petroleum resource definitions to provide consistency, transparency, and reliability to benefit stakeholders involved in international finance, regulation, and reporting. A milestone in standardization was achieved in 1997 when SPE and the World Petroleum Council (WPC) approved the “Petroleum Reserves Definitions.” Since then, SPE has continuously updated the definitions. In 2007, SPE, WPC, the American Association of Petroleum Geologists (AAPG), and the Society of Petroleum Evaluation Engineers (SPEE) approved the Petroleum Resources Management System, globally known as PRMS. The Society of Exploration Geophysicists (SEG) subsequently endorsed PRMS.

PRMS has been acknowledged as the oil and gas industry standard for reference and was used by the US Securities and Exchange Commission as a guide for its updated rules, “Modernization of Oil and Gas Reporting,” published in 2008.

SPE recognized that new applications guidelines were required for the PRMS. The SPE Oil and Gas Reserves Committee formed an Applications Guidelines Document Subcommittee in April 2007 to undertake this task. I was honored to be asked to chair the subcommittee. The original 2001 guidelines document was the starting point for this work. The goal was to have an inclusive process where the industry was involved and all stakeholder input was considered fairly by experts.
Drillpipe-Dynamics Measurements - Insight Into Drillstring Dysfunctions
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 145910, ’Drillpipe-Dynamics Measurements Provide Valuable Insight Into Drillstring Dysfunctions,’ by Constantijn Raap, SPE, Andrew D. Craig, SPE, and Ryan Graham, SPE, NOV, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed.

The drilling industry has become increasingly interested in drilling dynamics and in vibration as a cause of reduced drilling performance and downhole-tool and drillstring failures. Vibration data have been captured with measurement-while-drilling (MWD) tools in the lower bottomhole assembly (BHA). However, this approach is not always sufficient to understand the drillstring dynamics of more-complex applications. High-frequency vibration data were recorded at several strategic points within the drillstring by use of downhole dynamics recorders (DDRs). These data provided new insights into the dynamic behavior of drillstrings in high-angle wells.

Introduction

Drillstring vibration is a limiting factor when drilling horizontal and extended-reach wells. While rotating, long sections of drillstring are positioned on the low side of the hole. If sufficient friction exists in the wellbore while being rotated at constant speed from surface, the string will decelerate angularly, followed by a rapid increase in rotational speed. This torsional vibration, often referred to as stick/slip, generally increases with a combination of lower rotary speeds and higher surface weights. Typical consequences of torsional vibration may include overtorqued connections, torsional fatigue, and high wear of downhole-tool components, and it has been identified as the leading cause of damage to polycrystalline-diamond-compact bits.

Rotating the string faster than a system specific threshold or at increased compressive load causes the string to move up and down the wellbore. This snaking motion is characterized by movement in the lateral plane, which causes lateral shocks each time the BHA or pipe contacts the wellbore. Field experience indicates that higher rotary speeds generally lead to increased levels of lateral vibration. Severe lateral vibration, such as whirl, can have detrimental consequences, such as downhole-tool failure, impact damage to drill bits, and drillstring twistoffs. Both torsional and lateral vibration lead to reduced penetration rates and numerous unwanted BHA or bit trips.    

Another limiting factor encountered when drilling high-angle wells is the torque required to rotate the drillstring. High drillstring torque can limit the well stepout if the maximum available top-drive- or drillpipe-torque limit is exceed-ed. It is common that both high torque and vibration occur simultaneously.
Offshore Oil and Gas Installation - Aging and Life Extension
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146225, ’Aging and Life Extension of Offshore Oil and Gas Installations,’ by Iain Wright, ABB Engineering Services, prepared for the 2011 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 6-8 September. The paper has not been peer reviewed.

More than half of the offshore oil and gas installations in the UK Sector of the North Sea have been operating for at least 20 years. Most assets are approaching or operating beyond their original design intent. With the rise in oil and gas prices and advances in technology, there is an increasing requirement to extend the operational life of these assets. Safety-case regulations were modified to include a technical justification for extended operation, and the UK Health & Safety Executive (HSE) launched Key Programme 4 (KP4) to ensure that all duty holders have suitable management systems in place to address aging-related issues adequately.

Introduction

Coupled with the age is that most installations have encountered considerable changes in the composition of the well fluids over the life of the field and that there is an increasing trend for additional subsea tiebacks. All of these issues have raised concerns regarding the integrity and fitness for purpose of the structures and equipment for this extended life. This study aimed to answer key questions relating to aging and life extension.

Aging and Life Extension

According to HSE Research Report RR509—The Plant Ageing Guide, “Ageing is not about how old the equipment is. It’s about what is known about its condition, and how that’s changing over time.” This definition is illustrated in Fig. 1.

During the initial operation phase, design faults, installation issues, commissioning issues, or early-life operating faults are realized. Once equipment is in the mature stage, it generally is operating well within design limits, routine inspection and maintenance are being undertaken, and, in general, there is slow degradation. During the aging stage, the design limits for the equipment are approached, process changes usually have taken place, frequent repairs are required, and the overall degradation rate increases. In the end-of-life stage, the safe operating limits for the equipment are approaching, advanced inspection techniques are required at closer intervals to determine fitness for purpose, major repairs are required, and there is accelerating deterioration. The key to longer-term reliability and safety is to establish effective management systems early on to prolong the mature stage, because starting at later stages requires considerably more effort and cost.
Performance, Operability, and Risk Assessment of the Shtokman Floating Platform in Ice
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 22100, ’Approach to Performance, Operability, and Risk Assessment of the Shtokman Floating Platform in Ice,’ by Pavel Liferov, Guillaume Le Marechal, Marc-Marie Albertini, Michel Metge, and Erik ter Brake, Shtokman Development A.G., prepared for the 2011 Arctic Technology Conference, Houston, 7-9 February 2011. The paper has not been peer reviewed. Copyright 2011 Offshore Technology Conference. Reproduced by permission.

The Shtokman gas/condensate field (SGCF) is 610 km from Murmansk, Russia, in the Barents Sea. The water depth is approximately 340 m. The offshore facilities of the SGCF Phase-1 development will include an ice-resistant ship-shaped disconnectable-turret-moored floating platform (FP). Significant sea-ice invasions occur at Shtokman approximately 3 out of every 10 years. Icebergs also may occur in the SGCF area. Ice and iceberg management is planned to support the FP operations. The performance, operability, and risk of the FP in waters where occasional invasion of sea and glacial ice is anticipated were assessed.

Introduction

The main challenge was to achieve an appropriate reliability level at acceptable costs, while minimizing operational downtime. The main ice-related challenges identified in the prefront-end engineering and design (FEED) and updated during the FEED included FP loss of station keeping because of actions from sea ice, FP loss of station keeping because of actions from icebergs, and underhull ice interaction in the riser-connection area.

It was decided early on to establish challenging but realistic design targets for the main systems (e.g., hull, mooring, and disconnection system) and, in parallel, work on design of operational measures, including assessment of efficiency and reliability. Further, quantitative operability and risk assessments of the entire system were performed to evaluate potential optimization needs.

Ice-Related Design and Operating Philosophy

The FP was designed as an ice-resistant disconnectable production unit, able to withstand independently almost all ice and iceberg actions expected to occur at Shtokman. The following conditions are the design limits, and acceptable response criteria under these conditions and interaction scenarios must be satisfied.

Ultimate-limit-state (ULS) mooring safety factor under:

Head-on interaction with unmanaged 100-year-return-period (YRP) ice ridge (with corresponding companion environmental actions)

Ice vaning in unmanaged 100-YRP level ice (with corresponding companion environmental actions)

Interaction with 10,000-YRP iceberg in open water (for demonstration purpose, not for use in operations)

5000-t horizontal load (as practically achievable value, on the basis of results from initial studies)
The Second Unconventional Gas Wave
Authors: Miller Jeff
Published: February 2015

Guest editorial

Gas exploration activity in North America looks like it is in the doldrums. In the past 12 months, gas-directed North American rig counts have fallen by almost half. This is easy to understand. Since the beginning of 2010, front-month gas futures prices have fallen from USD 5.60/MMBtu to their current level of USD 3.60/MMBtu. I have a bullish view on the long-term future of natural gas. When accounting for all of the upside influences—environmental imperatives, relentless demand growth in the developing world, the potential of the domestic power sector, revitalization of the US industrial base, and downstream innovations such as gas to liquids (GTLs)—the picture looks positive. At the same time, I have a firm belief that continuing innovation will drive efficiency, making gas an even more attractive alternative and leading to more exploration and development. These indicators lead me to believe a second wave in the development of the North American gas business is on the way.

The first wave has been quite a ride. Only a few years ago, gas industry pundits assumed that new gas demand could only be met with imports. An entire subindustry was developed around the regasification, storage, and transport to market of imported liquefied natural gas (LNG). Today, LNG regasification facilities are largely idle. Instead of increasing, gas imports have fallen dramatically—from 12.6 Bcf/D in 2007 to less than 9 Bcf/D in the most recent 12 months.

Although gas production has increased dramatically, from just under 55 Bcf/D in 2007 to a current rate of 69 Bcf/D, the increases in production have been absorbed incrementally, without long-term structural adjustments in the US energy economy or significant investments in infrastructure. Existing gas plants displacing coal in the power sector and reductions in imports have absorbed more than 70% of the increase in gas production.

The United States is still a net gas importer, but the industry is now focused on developing export markets. Those markets are there. Demand growth in China is almost certain for a generation. If Japan follows up on its commitment to step away from nuclear power, new supplies will need to be found there.

Exporting gas will require us to adopt workable regulations, develop infrastructure, and change a mind-set. The United States is accustomed to thinking as an energy importer. As new sources are developed, we tend to guard them jealously and reserve them for domestic use. The Federal Energy Regulatory Commission approves the construction of LNG liquefaction facilities and the Department of Energy grants export licenses based on a “public interest” standard.
Techbits: IPEC 2012: Promoting Industry Diversity
Authors: JPT staff _
Published: February 2015

Techbits

The International Professionals in Energy Conference (IPEC 2012) “Empowering Women’s Leadership” was held recently in Kuwait under the patronage of the Kuwait Minister of Oil and Chairman of the Board of Kuwait Petroleum Corporation Hani A. Hussain.

During the two days of IPEC 2012, attendees representing international oil companies, national oil companies, multinational service companies, consulting firms, and academia discussed topics related to gender diversity in the industry. More than 270 delegates representing 53 companies from 15 countries attended.

The opening ceremony featured Farouk Al Zanki, deputy chairman of the Board of Directors and CEO, Kuwait Petroleum, and Hosnia Hashim, deputy managing director, North Kuwait, Kuwait Oil, who was also the conference chairperson. The executive plenary session included Sami Al Rushaid, chairman and managing director, Kuwait Oil; Maha Mulla Hussain, chairperson and managing director, Petrochemical Industries Company; Andrew Gould, chairman, BG Group; and Bernadette Spinoy, senior vice president, refining and petrochemicals Eastern Hemisphere, Total. The speakers shared their personal experiences and their companies’ strategies for creating balanced leadership.

Held alongside IPEC was a Region-al Education Day, attended by 200 students from public and private schools in Kuwait. The aim was to introduce students to the discipline of petroleum engineering and the industry in general.

Three key concepts arose during the conference:

The inclusion, retention, and empowerment of women in the workforce is a clear business necessity.

Companies need to ensure that all employees positively embrace the increased presence of women in the workforce.

The implementation of gender-balanced guidelines for promotion processes is necessary.

The inclusion, retention, and empowerment of women was described as important because the expansion plans of the industry to meet global energy demand will require new staff. The second concept, one met with surprise by several attendees, is the recognition of the need to train men in the industry to accept and embrace the incremental presence of women in all roles and ranks of the workplace, especially in field operations, where a female presence is still uncommon in many places of the world. In field operations, special accommodations and facilities may be needed to follow cultural acceptance.

The third key concept will require implementation of gender-balanced guidelines for promotion to maintain managerial balance in companies.

Panelists concluded that the industry’s workforce is in need of change to reach its potential, and that future energy challenges will require richer and more diverse viewpoints. The oil industry must incorporate concepts of diverse work teams as well as best practices in diversity and inclusion processes to enable and promote contribution from professionals with different experiences and perspectives. This diversity will allow for better decisions.
Unconventional Exploration Reaches: Alaska's North Slope
Authors: Rassenfoss Stephen
Published: February 2015

North Slope Shale

On the day last February that the US Geological Survey (USGS) came out with a report saying up to 2 billion bbl of oil could be produced from shale formations on the North Slope of Alaska, a company was already planning to drill on its 500,000-acre lease.

That was a striking change at the agency where years separated the release of assessments and exploration in plays such as the Marcellus said David Houseknecht, a research geologist for the USGS and the lead author of the North Slope assessment.

The explorers and the government geologists drew on similar sources to conclude the North Slope could be a likely spot for the next US shale exploration boom.

While the USGS was working on its North Slope evaluation, geologists like Ed Duncan were looking for signs the rocks that were the source of oil that migrated over long periods into huge conventional reservoirs, such as the Prudhoe Bay, Kuparuk, and Alpine, could also be rich sources of oil.

Using what he’d learned early in his career working the North Slope and later as a consultant for companies seeking new shale plays, Duncan and his wife Karen Duncan, formed a company called Great Bear Petroleum and put in a surprise bid at the December 2010 Alaska state lease sale.

“I was stunned by the potential, with three of the most prolific oil source rocks and nobody was doing anything with them,” said Duncan, who is president and chief executive officer at Great Bear.

At the time he told the story of how he came to explore the North Slope, Duncan was in Golden, Colorado, at a Weatherford lab studying the core samples collected from Great Bear’s test wells, the Alcor and the Merak, drilled in the summer of 2012.

The wells near the gravel road that parallels the Trans-Alaska Pipeline penetrated all three source rock formations. The early evaluations were all in line with expectations but in late December he was just beginning to see the results of the tests of formations so rarely seen that a USGS geologist came out to examine them.

Duncan hopes to drill a horizontal well, fracture it, and do a production test next, but: “As much as I would love to say here is the result, let’s go ahead with a fracture-flow test, that is not the case,” he said.

“We are learning a tremendous amount every day,” Duncan said after 2 days in Golden. But critical tests on the rock properties indicating whether it could be effectively fractured would not come in until February. “My father would say there is plenty of wood to chop here,” he said.
Tight Resources, Promising Economics: The Permian Basin Continues Yielding Liquid Riches
Authors: Beckwith Robin
Published: February 2015

Permian Basin

There is no doubt that the 86,000-sq-mile Permian Basin, encompassing 52 counties in west Texas and eastern New Mexico, is experiencing a renaissance in drilling activity. According to the Railroad Commission of Texas (RRC), the Texas Permian Basin rig count climbed from 129 in 2005 to 355 in 2011, sustaining a dip to 103 in 2009 with no drop in crude oil production. Total Permian Basin rig count climbed to 500 in May 2012, according to a US Energy Information Administration (EIA) report, and as of late December 2012, stood at 454. The number of drilling permits issued by the RRC has exhibited a similar rise, from 4,459 in 2005, with a downdip to 3,369 in 2009 and then a steep climb to 9,347 in 2011.

The price of natural gas remains depressed in the US, largely because of a glut due to a rush to exploit very tight gas resources in shale plays such as the Marcellus, Eagle Ford, Barnett, Haynesville-Bossier, Fayetteville, Woodford, and Bakken. A trend over the past few years has therefore been building towards a focus on liquids-rich plays.

As a result, US production of crude oil is reaching levels not seen in 15 years, at approximately 2.1 billion bbl/year as of September 2012, according to the US Department of Energy’s (DOE) EIA. The US now produces an average of 6.41 million BOPD, a 14% increase from 2011, according to a December 2012 DOE report—around 50% of the crude oil it consumes.

The two US states emerging as yielding the greatest amount of liquids are North Dakota (the Bakken) and Texas (Permian Basin and Eagle Ford).

From September 2011 through September 2012, Texas onshore crude oil production increased by more than 500,000 BOPD, due to increases in Eagle Ford and Permian Basin production.

The Permian Basin now accounts for more than 18% of domestic US crude oil supply. It has more than 400 active drilling rigs, by far the most of any US basin, that are drilling a large number of wells very quickly.

The EIA estimates (Fig. 1) that crude oil production from the Permian Basin surpassed 1.25 million B/D in November 2012, 33% greater than the estimated 0.93 million B/D in the Western Gulf basin and 45% greater than the 0.86 million B/D in the Williston basin.
Pioneer Resources: Targeting the Wolfcamp with Integrated Services
Authors: JPT staff _
Published: February 2015

Permian Basin

Pioneer Natural Resources is a large independent oil and natural gas company, with resources throughout the US—in south Texas, the Rockies and Mid-Continental regions, the Barnett shale, and in Alaska’s Oooguruk field. The company also is one of the most active drillers in Texas’ Spraberry/Wolfcamp oil field in the Permian Basin. Covering nine counties, the Spraberry field produces sweet crude and gas from formations between 6,700 and 11,000 ft below the ground. Pioneer is also in the early stages of a new horizontal drilling program in the Wolfcamp shale interval of the Spraberry field.

In a recent interview, Pioneer’s Tom Spalding, vice president, geoscience, explained, “Pioneer is a major operator in the Spraberry vertical and the horizontal Wolfcamp shale—in the center of the basin.”

The company is interested in drilling deeper in the Spraberry, targeting the Strawn, Atoka, and Mississippian. “In fact,” said Spalding, “Vertical wells with multistage completions that include these deeper zones accounted for about 65% of our 2012 vertical drilling program.”

Pioneer boasts one of the largest acreage positions in the Permian Basin, approaching 900,000 acres—and it is highly leased up. “We also have a big push on with unconventional horizontals drilling into source rock—the Wolfcamp, which is the major source rock in the area,“ said Spalding. “The beautiful thing about the Midland basin Wolfcamp formation is it just happens to be in the right window—buried to the right depth and exposed to the proper temperatures—so that over time the kerogen has ‘cooked’ so it is converted to oil (liquids).”

 This “right window” underlies across the Permian Basin, where the Wolfcamp is a thick formation—the source rock—underneath other formations, such as the Spraberry. Pioneer has been drilling its southern 200,000 acres first, to hold some expiring leaseholds. “The Wolfcamp is a little shallower there,” he said.

Deeper drilling in the Spraberry, targeting the Strawn, Atoka, and Mississippian, accounted for 65% of Pioneer’s 2012 vertical drilling program. All these formations lie beneath the Wolfcamp, which lies beneath the Spraberry. The deeper drilling provides the potential to add up to 100,000 BOE (in addition to the 140,000 BOE obtained from the commingled Spraberry and Wolfcamp).
Molecular-Dynamics Study Examines Effect of Nanoparticles on Oil/Water Flow
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 156995, ’Effect of Nanoparticles on Oil/Water Flow in a Confined Nanochannel: A Molecular-Dynamics Study,’ by Jianyang Wu, Jianying He, Ole Torsæter, SPE, and Zhiliang Zhang, Norwegian University of Science and Technology, prepared for the 2012 SPE International Oilfield Nanotechnology Conference and Exhibition, Noordwijk, The Netherlands, 12-14 June. The paper has not been peer reviewed.

Experiments on oil/water nanoparticle flow behavior in confined clay nanochannels were conducted with molecular-dynamics simulations. Three sizes of nanochannels and different numbers of nanoparticles were considered. The results show that the pressure to drive the oil/water binary mixture through a periodic confined channel increases dramatically with the reduction of the channel size. In the absence of nanoparticles, the pressure increases with the propelled displacement. An opposite behavior is observed in the oil/water system mixed with a small amount of nanoparticles: The pressure decreases with the increase of the displacement. The findings from molecular-dynamics simulations may elucidate the role of nanoparticles in the transport of oil in nanoscale porous media.

Introduction

One of the more promising applications of nanotechnology in the field of oil and gas, in particular for enhanced oil recovery and drilling, is the creation of a new generation of fluids. Nanofluids are a class of fluids engineered by dispersing nanoparticles (nanofibers, nanotubes, nanowires, or nanodrops) in base fluids. Nanofluids were first recognized because of their thermal properties.

The most commonly studied nanoparticles for enhanced oil recovery are the spherical silica nanoparticles with a diameter in the range of several to tens of nanometers. Functionalized nanoparticles can form a highly stable emulsion to determine the oil-saturation situation, improve the oil-flow mechanism, and identify the location of bypassed oil. Although the exact interface mechanisms are still unclear, it is generally expected that silica nanoparticles will also reduce the surface tension between oil and rock and enhance the depletion of oil from porous media. Before full-scale deployment of silica nanoparticles occurs, many issues remain to be resolved, such as how the particles behave in a reservoir and how to design the appropriate silica nanoparticles.

This study focused on the fundamental understanding of the role of silica nanoparticles in the oil/water binary mixture in a confined nanochannel.

Structure and Simulation Details

Rocks that are rich in kaolinite are known as kaolin clay. Kaolinite has the chemical composition Al4Si4O10(OH)8(Fig. 1). Kaolinite is a layer clay with neutral charge, and the asymmetric structure allows the formation of hydrogen bonds between consecutive layers.
Techbits: First SPE Workshop-Webinar Held on Waterflooding
Authors: JPT staff _
Published: February 2015

Techbits

The Technical Aspects of Waterflooding workshop held 23 October in Long Beach, California, was the first SPE event to involve both live participants and members participating around the world through a real-time video feed. The workshop drew more than 70 participants from various companies and organizations, including Occidental, Signal Hill Petroleum, Berry Petroleum, Santa Maria Energy, Termo, Spec Services, the California State Lands Commission, SPE board members, and students from the University of Southern California and California State University of Long Beach. The workshop was held by the SPE Los Angeles Section and the one-day live webinar by SPE. Following are highlights from the workshop.

When Water and Oil Mix byAbbas Firoozabadi

Water and oil sometimes mix due to formation of certain structures known as emulsions, small droplets of water in oil or small droplets of oil in water that add surfactants.

Waterflood Management and Surveillance byGanesh Thakur

This presentation illustrated how practical application of surveillance and monitoring principles are key to understanding reservoir performance and identifying opportunities that can improve oil production and ultimate oil recovery.

Waterflooding Process and Design by Abdus Satter

Waterflooding as a process is the most widely used post-primary recovery method in the United States and contributes substantially to current production and reserves.

Waterflood on a Chip byBaldev S. Gill

Microfluidics are used to displace one phase with another in a water-wet prefabricated microchip and the displacement can be seen under a microscope.
Application of a Nanofluid for Asphaltene Inhibition in Colombia
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24310, ’Application and Evaluation of a Nanofluid Containing Nanoparticles for Asphaltene Inhibition in Well CPSXL4,’ by R. Zabala, E. Mora, C. Cespedes, L. Guarin, H. Acuna, and O. Botero, Ecopetrol; J.E. Patino, Petroraza; and F.B. Cortes, Universidad Nacional de Colombia, prepared for the 2013 Offshore Technology Conference Brasil, Rio de Janeiro, 29-31 October. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.

This paper describes the evaluation of a nanofluid containing nanomaterials with high adsorption capacity used for asphaltene inhibition in the volatile Cupiagua Sur oil field in Colombia. Asphaltene precipitation has been identified as one of the most potentially damaging mechanisms affecting this field’s productivity. The goal of the injection of nanofluids containing nanoparticles of alumina with high surface area is to absorb the asphaltenes and carry them with the condensate, avoiding precipitation near the wellbore.

Introduction

The Cupiagua Sur field is located 110 km northeast of Bogota in the foothills of the Colombian Andes, close to other fields such as Floreña, Pauto, Volcanera, Recetor, Cupiagua, and Cusiana (Fig. 1). Despite the fact that Cupiagua Sur is very close to Cupiagua, this reservoir is totally independent and separate. It is a compositional volatile-oil reservoir with an average gravity of 38°API; there is no free-gas cap at initial conditions (for a discussion of asphaltene precipitation in volatile oil, please see the complete paper). The main formations are Mirador and Barco, which are quite similar in terms of petrophysical and fluid properties (average permeability is 21 md, and average porosity is 6.5%).

Cupiagua Sur is a prolific oil field that in 15 years of production has recovered 88 million STB/D gross out of 189 million STB/D originally in place from Mirador and Barco reservoirs in a developed area with four producer and two injector wells.

The current reservoir conditions in this field are highly dependent on the way the reservoir has been produced. The first production well, CPXP1, started producing in March 1998, while the first gas-injector well went into action in January 2000; at that time one volatile well was on production. There are currently six active wells in the field. There are four producers and two gas injectors.

Oil production reached its peak in March 2001 at 41,722 STB/D. The average gas production at that date was 175 MMscf/D. Today, the recovery factors are 48.2% and 29.5% in the Mirador and Barco formations, respectively. There was no production plateau in Cupiagua Sur; instead, a constant decline rate is observed. This indicates the extreme conditions under which the reservoir was depleted, as well as the sources of damage.
Conversations: Achieving Immortality
Authors: Fattahi Behrooz
Published: February 2015

President's column

I am writing this column on the other side of the globe from my home in California, after flying for almost 20 hours to get here. The details of my trip, as in the case of many others, were arranged by SPE staff in Dallas working in concert with the SPE staff in our six other offices around the world. This first tour of 2010, 2½ weeks long, started in Jackson, Mississippi,  where I spoke at a gathering of SPE members; on to Dallas for the SPE Board of Directors meeting; to Houston, where I spoke at an annual industry executives breakfast; on to Mumbai, India, to speak at the SPE Oil and Gas India Conference, and a 6-hour drive to visit a student chapter in Pune, India; and finally to Manama, Bahrain, to speak at the SPE Deep Gas Conference and Exhibition, before I go back home for a week to prepare for the next trip. This is a typical travel schedule for the SPE president nowadays. Traveling to some 30 countries, roughly 60 locations, traversing the globe for approximately 300,000 km, and for as many as 75 weeks on the road is not unusual for a president’s 3-year term as president-elect, president, and past president. Our professional society is truly an international organization.

Presiding over a complex and international operation requires reaching out to all of our members wherever they may reside. Today, we have more than 92,000 members scattered in 117 countries, with 173 sections and 207 student chapters. More than 55% of SPE’s total members, including more than 80% of student members, reside outside the U.S. (Figs. 1 and 2). But although this is a dramatic demographic shift since its beginnings, SPE’s globalization is not merely measured by the shift in its membership statistics.

SPE’s journey toward globalization started more than 50 years ago, with the establishment of the Venezuela Section in 1956. Almost 40 years ago, the first Offshore Europe conference was held in Great Yarmouth, Scotland, under the name Oiltech. In 1979, SPE held the first Middle East Oil and Gas Show and Conference. Although during the 1980s the industry suffered a downturn and roughly half of all jobs were lost, SPE membership experienced a growth throughout the decade. And it was in 1989 when the first Asia Pacific Oil and Gas Conference and Exhibition was held.
Technology Partnerships for Challenging Environments
Authors: Mahoney Garry P.
Published: February 2015

Guest editorial

It is widely accepted today that for the remainder of Hydrocarbon Era, global energy stability will rely increasingly upon crude oil and natural gas recovered from giant offshore fields, many of which will be located far from major markets, in hostile environments such as ultradeepwater and the Arctic. Less understood is the fact that large-scale, multibillion-dollar developments are precisely where the principal technological and economic drivers to push beyond technological boundaries are the strongest and where stakeholder participation and partnering is most complex.

The different agendas of the various partners and stakeholders in such developments often compound the challenges of technological complexity. For example, a national oil company typically is seeking to ensure long-term domestic political stability and to invigorate the national economy with development of natural resources. A top-tier international oil company is generally aiming to maintain global production, improve unit production costs, and maintain reserves, while, for most smaller operators, the drivers tend to be rapid and reliable realization of assets that feed dynamic balance sheets. In the case of technology providers—namely vendors, constructors, and fabricators—the drivers tend to be stretching applications of established technology, early capitalization of investment in new equipment/assets, maintaining competitiveness, and vying for market share.

Against a backdrop of daunting technological challenges, operators, equity owners, and other stakeholders in demanding frontier developments frequently differ on such fundamental issues as contracting strategies; the timing of project milestones; or the program for technology selection, maturation, and implementation. Opinions are often divided, also, over how to balance the costs and risks of technology selection, or the extent of a given technological stepout. Such disagreements are compounded by the very different business drivers and risk appetites of project partners, stakeholders, and technology providers.
Talent Council Workshop Focuses on Diversity Solutions
Authors: Howes Susan
Published: February 2015

Talent & Technology

To meet the need for people to replace those due to retire during the “big crew change,” the oil and gas industry must attract, retain, and promote a more diverse workforce than it has in the past. In October 2009, the SPE Talent Council held a Diversity Workshop in Paris to explore ways the industry can be more attractive to today’s diverse work-force. Human resources professionals from 11 employers participated, sharing best practices in encouraging diversity in the workplace.

The SPE Talent Council, chaired by Fabrice Bouchard of Schlumberger, provides a forum in which industry and academia collaborate on initiatives to increase the quantity and quality of industry talent, including initiatives to increase industry attractiveness to a diverse workforce. Numerous opportunities exist for employers to collaborate in encouraging diversity/inclusion in the industry, including

Benchmarking maternity policies, especially for expatriates on international assignments

Encouraging more women and ethnic minorities to study engineering, math, and science

Sharing best practices in staffing difficult locations with women and ethnic minorities

Supporting dual-career couples

Providing industry role models from diverse backgrounds

Preparing for the crew change by accelerating competency development

Transferring the knowledge from the generation retiring to new recruits

Encouraging women and minorities to take assignments in global projects and in operations

Implementing nationalization strategies including the development of national work forces

Initiatives to Encourage Diversity Discussed

A number of examples of initiatives to encourage diversity were shared during the workshop. From employee networks and diversity training sessions to adapting the field work environment to women employees, participants elaborated on the many initiatives taken by their companies to encourage diversity in the workplace.

Nicky Jenkins, Baker Hughes Diversity manager, described a women’s resource group that was enthusiastically received among employees. Baker Hughes also launched an internal photographic competition to ensure inclusion of photos representative of its diverse workforce in its media bank.