bluuebunny/crossref_metadata_2025_split huggingface dataset:
Siri Pilot Project: First Offshore Extraheavy and Viscous Oil
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 20134, ’Siri Pilot Project - First Offshore Extra Heavy and Viscous Oil (12.3 API) Ever Produced,’ by Alexandre Dutra Sayd, Andre Luiz B. Moco, Celso C.M. Branco, Edson T. Kato, Ivan Parreiras de Carvalho Jr., Joao A. Rosseto, Jose Augusto da Silva Neto, Josiane L. Diniz, Marcelo Brennand, Marcelo Guarda, Miguel Pittella Franco, and Thomas Edison Brasil, Petrobras, originally prepared for the 2009 Offshore Technology Conference, Houston, 4-7 May.
The full-length paper describes the appraisal and pilot testing of a large, offshore highly heterogeneous carbonate 12.3ºAPI reservoir in 100-m water depth. The successful pilot production started on 31 March 2008 to the floating production, storage, and offloading (FPSO) vessel Cidade de Rio das Ostras (Fig. 1). Since then, pilot production has been monitored closely by permanent-down-hole-gauge (PDG) and electrical-submersible-pump (ESP) sensors used to update a reservoir-simulation model. Preliminary results show more-viscous oil than initially expected in a more complex reservoir.
Introduction
In the early stages of exploration and production of the Campos basin offshore Brazil in the late 1970s and early 1980s, a shallow (900-m true vertical depth) Siri carbonate reservoir was discovered in water depths of 100 m. Although the volume in place was large (currently estimated at more than 300 million m3), it was considered noncommercial because of the 12.3°API oil gravity and 320-cp viscosity. At that time, there was an abundance of lighter oils to be developed beneath the same area. In addition, the technology for extracting such heavy and viscous oil in an offshore cold environment had not been developed yet. In 1993, a vertical development well, designed for the deeper reservoir, tested and collected a bottomhole oil sample. Operational problems during the well test, including water production, made it difficult to quantify reservoir parameters. In 2002, new studies were made, which led to the drilling and testing of a pilot vertical well, later sidetracked to a long-horizontal-section (2000 m) well, revealing a better-than-expected reservoir scenario. An ESP-aided flow test in the vertical well produced an impressive productivity index. In this context, the Siri reservoir appeared as a candidate for a pilot production project. Many other heavy- and extraheavy-oil discoveries were made in Campos basin, which caused additional interest in testing and development technologies.
Characterization of a Complex Carbonate Heavy-Oil Reservoir
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 120423, ’Characterization of Complex Carbonate Heavy Oil Reservoir - A Case Study,’ by Afzal Iqbal,John Smith, Ali Reza Zahedi, Deemer Arthur, and Falah M. Al-Yami, Saudi Arabian Chevron; W. Scott Meddaugh, Chevron Energy Technology Company; Mansoor A. Rampurawala, SPE, Bingjian Li, SPE, and Ihsan Gok, SPE, Schlumberger Oilfield Services; and Talal Al Enazi, Kuwait Gulf Oil Company, originally prepared for the 2009 SPE Middle East Oil and Gas Show and Conference, Bahrain, 15-18 March.
The First Eocene reservoir is the shallowest producing interval of the Wafra field in the partitioned Neutral Zone between Saudi Arabia and Kuwait. Characterization of this heavy-oil reservoir is challenging because of observed variations in oil viscosity, heterogeneity related to complex mineralogy, a possible dual-porosity system, and the presence of fractures of varing scales. The full-length paper presents several aspects of an integrated approach to characterize the reservoir.
Introduction
Currently, a large-scale steamflood pilot (LSP) consisting of sixteen 2.5-acre inverted-5-spot patterns is being installed. This will be the first multipattern steamflood of a carbonate reservoir in the Middle East.
Oil was discovered in the First Eocene in 1954, and full-scale development began in 1956. The First Eocene has produced only 4% of original oil in place (OOIP), and primary recovery is not expected to exceed 10%. The oil gravity in this heavy-oil reservoir varies from 14 to 20ºAPI. The First Eocene is a depletion-drive reservoir with partial solution-gas drive and limited aquifer support. The estimated gross OOIP within the currently delineated field limit is more than 10 billion reservoir bbl.
The reservoir mainly consists of dolomitized packstones and grainstones deposited under arid-to-semiarid conditions on a shallow, very gently dipping, low- to moderate-energy inner shelf or ramp setting in a gently dipping, restricted ramp environment. The presence of minor interbedded evaporites suggests restriction was occasionally sufficient for the development of hypersaline lagoons and sabkhas. The shallowing-upward cycles are capped by mud-dominated rocks, hardgrounds, and exposure surfaces. The average porosity is 35% and the average permeability is 250 md over the gross interval. Well-log and core-plug porosity values greater than 50% are common, and measured permeability values range up to 5,000 md. The First Eocene reservoir has an average depth of approximately 1,000 ft and a gross thickness of approximately 750 ft. Three wells were used in the study to demonstrate the approach of integrating log and core data to evaluate reservoir heterogeneity.
Comments: Drilling Slowdown
Authors: Donnelly John 
Published: February 2015

Editor's column
Nearly a year after the Macondo blowout in the US Gulf of Mexico, activity in one of the world’s great hydrocarbon basins is sparse and the future appears uncertain. Although the drilling moratorium was lifted by the federal government several months ago, approval of deepwater drilling permits has been slow in coming and the regulatory environment is unclear.
Drilling contractors are certainly suffering. Seahawk Drilling, one of the largest operators of shallow-water rigs in the Gulf of Mexico, announced last month that it would file for bankruptcy and sell its assets to a competitor. The company blamed the US government for regulations that had stifled drilling activity. Seahawk was “forced to seek strategic alternatives only after an unprecedented decline in the issuance of offshore drilling permits following the Macondo blowout,” Seahawk CEO Randy Stilley said in a statement announcing the bankruptcy. “The decision by regulators to arbitrarily construct unnecessary barriers to obtaining permits they had traditionally authorized has had an adverse impact not only on Seahawk, but on the sector as a whole.”
Seahawk’s assets will be acquired by Hercules Offshore in a cash and stock deal worth about USD 100 million. The deal was the second major consolidation among US rig contractors in a week, following Ensco’s acquisition of Pride International.
US Interior Secretary Kenneth Salazar in May imposed a moratorium on drilling in the Gulf and lifted it in October. Drilling in shallow water of 500 feet or less was not subject to the moratorium but the issuance of new drill permits was greatly slowed.
At a Baker Institute gathering last month in Houston, industry representatives, scientists, consultants, and government officials discussed the future of the Gulf post-Macondo. That future will depend on how US drilling policy and safety standards evolve, the panelists agreed. In 2010, the US Gulf of Mexico produced 1.7 million b/d of oil and 6 bcf/d of natural gas, just under a quarter of total US oil output and 10% of total gas production, said J. Robinson West, chairman and chief executive officer of PFC Energy, one of the speakers at the event. “If oil and gas drilling are able to continue without constraint in the Gulf, it is the young fields in ultradeep water that will make the greatest contribution to US domestic oil production and energy security,” West said. By 2020, more than half of the Gulf’s production is projected to come from ultradeep waters.
Several industry executives thought that the industry and federal regulators would soon be to a point where the issuance of deepwater drilling permits could resume. Michael Bromwich, director of the federal agency overseeing drilling activity, said he expects permits for deepwater projects to begin soon, at least before the end of the second quarter.
Meanwhile, rigs from the Gulf are leaving for other basins around the world such as Brazil and west Africa. “The deepwater industry is global and will take its capital, equipment, and jobs to other basins if it cannot operate in the US,” West said.
Technology Focus: Hydraulic Fracturing (March 2011)
Authors: Chipperfield Simon 
Published: February 2015

Technology Focus
Beware the “Commoditization Trap”1!
Commoditization is the evolutionary process that reduces all products to their lowest common denominator. This process has many advantages in unconventional gas in which large resources can be developed efficiently with such “factory-style” development concepts. The commoditization-trap problem can arise when one becomes focused solely on producing a product more cheaply without consideration for the quality and new-product development.
The dangers of the Commoditization Trap can be observed when analyzing the SPE hydraulic-fracturing paper population, which, while increasing exponentially over the last 30 years, is now led by operators in less than 15% of cases (down from 37% operator driven in 1975).2 Lead-service-company contribution has, however, increased from 20 to 40% over the same period. This change high-lights the industry perception that fracturing requires little definition (a phase of increased operator involvement) and instead requires a focus on commoditization (a phase for increased service-company involvement).
Viewing fracturing as a commodity may seem reasonable considering that it has been in use for more than 60 years. However, the types of reservoirs on which this technology is used are changing rapidly and are challenging the fundamental assumptions upon which our existing candidate selection and design methodology are built.
Some operators are adapting learning processes to ensure against the Commoditization Trap.3 However, the constant shift in technical contribution from operator to service company clearly highlights that this is not an industry-wide view.
Hydraulic fracturing as a commodity is an industry misconception, and greater value can be added by those who have not fallen into the Commoditization Trap.
Hydraulic Fracturing additional reading available at OnePetro: www.onepetro.org
SPE 133456 “Thirty Years of Gas-Shale Fracturing: What Have We Learned?” by George E. King, SPE, Apache Corporation. (See JPT, November 2010, page 88.)
SPE 127888 “Modeling Fluid Invasion and Hydraulic-Fracture Propagation in Naturally Fractured Rock: A 3D Approach” by J. McLennan, SPE, University of Utah, et al.
SPE 137818 “Improved Proppant-Transport System for Slickwater Shale Fracturing” by N. Kostenuk, SPE, Trican Well Service, et al.
1http://www.imaginellc.com/avoiding-commoditization-part1, accessed 31 January 2011.
2This percentage refers to search results by company affiliation of the primary author of SPE papers.
3 The New Encana—http://www.encana.com/investors/presentations/pdfs/corporate-presentation.pdf, accessed 31 January 2011.
Evaluation of Aquifer Diversion After Large Polymer-Gel Water-Shutoff Treatments
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 132978, ’Quantitative Evaluation of Aquifer Diversion to Surrounding Wells After Multiple Large Polymer Gel Water Shutoff Treatments,’ by Ben Turner, SPE, Tiorco, and Jude Nwaozo, SPE, and Brad Funston, SPE, Marathon Oil Company, originally prepared for the 2010 SPE Production and Operations Conference and Exhibition, Tunis, Tunisia, 8-10 June. The paper has not been peer reviewed.
From April through August of 2009, seven producing wells in the Spring Creek field in the Big Horn basin of Wyoming were treated with chromium-acetate-crosslinked polyacrylamide in an attempt to reduce water production, lower fluid levels, and achieve greater drawdown, resulting in improved oil production. The wells were chosen because of their high productivity, high water cut, suboptimal operation because of pump limitations, and in some cases, marginal economics.
Introduction
The Spring Creek field is on the west flank of the Big Horn basin in Park County, Wyoming. Structurally, Spring Creek forms an asymmetrical anticline. The main oil reservoirs in Spring Creek are the Tensleep sandstone (Pennsylvanian) and the Phosphoria formation (Permian).
Both the Phosphoria and the Tensleep are connected to prolific aquifers that supply reservoir energy, but also supply a high rate of water. In most wells in the field, both formations are produced and commingled, but in many wells, the Tensleep is so productive that the well is limited in lifting capacity and the Phosporia has not been perforated. The well spacing in the field averages approximately 5 acres.
Strategy
The operator has an extensive history of shutting off water production by use of chromium-crosslinked polyacrylamide gels. By using chromium acetate as a delayed crosslinker for partially hydrolyzed polyacrylamide, a large volume (as much as 11,500 bbl in this case) can be injected and then allowed to cure for a week. When the gel cures, it reduces the permeability of the fracture and is able to withstand a high differential pressure such as that seen in the near-wellbore region of a producing well. The gel is bullheaded through tubing, with a packer set above the productive formations. Because of the large permeability difference between the fractures and the formation matrix, the gel will penetrate the fractures and significantly reduce the permeability, reducing the water production and fluid level, thus allowing the well to be pumped off and oil production to be increased. This technique has been used quite successfully in several hundred applications throughout the USA.
Alaskan Heavy Oil: First CHOPS at an Untapped Arctic Resource
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 133592, ’Alaskan Heavy Oil: First CHOPS at a Vast, Untapped Arctic Resource,’ by J.P. Young, SPE, W.L. Mathews, SPE, and E.J. Hulm, SPE, BP Exploration Alaska, originally prepared for the 2010 SPE Western Regional Meeting, Anaheim, California, 27-29 May. The paper has not been peer reviewed.
Alaska’s North Slope is a world-class petroleum resource basin with two of the largest producing fields in North America, Prudhoe Bay and Kuparuk River unit. What is not widely known is the vast resource of heavy oil above these reservoirs. Although comparable in size to these fields, it remains untapped as a result of the complexity of producing heavy oil in an arctic environment. The keys to commercializing this heavy-oil resource are primarily technology and favorable economics.
Introduction
The total North Slope heavy-oil resource is defined by approximately 1,500 wells that penetrate the Ugnu sands for deeper targets and multiple high-quality 3D-seismic surveys. Resource size ranges from 18 to 27 billion bbl of oil in place, and the oil is found in multiple reservoir zones extending across the basin. Initial appraisal is focused on the 12 to 18 billion bbl within the Lower Ugnu (M-sand) reservoirs.
The Ugnu structure is characterized by a normal-faulted monoclinal dip toward the northeast. The depth of the Ugnu pool varies from 4,500 ft in the east to 3,000 ft in the west. Multiple fault families are present, as indicated by 3D seismic. The faults tend to compartmentalize the Ugnu reservoirs by providing effective updip and lateral seals.
Lower Ugnu oil quality improves to the east, corresponding to increased burial depth from west to east. The deeper, less-viscous oil in the east is believed to be suited to simple “cold”-production techniques that exploit solution-gas drive. The shallower, heavier oil in the west is believed to be suited to energy-intensive thermal techniques that heat the oil in situ.
Reservoir-Performance Variability
Excluding mechanical issues, most variation in well rates and recovery is likely to be associated with changes in key reservoir and fluid properties. The Lower Ugnu reservoir sands are highly unconsolidated, which limits the ability to acquire quality core samples and measure key reservoir parameters accurately. In addition, the sands were deposited as fluvial-deltaic channels, which are among the most heterogeneous reservoir types.
Technology Focus: Seismic Applications (March 2011)
Authors: Kleemeyer Gerd 
Published: February 2015

Technology Focus
The number of papers available for this feature almost tripled compared to the introduction of the Seismic Applications feature in 2009. The encouraging increase and the diversity of covered subjects mirror current challenges and the latest developments in seismic technologies. Striking, but not unexpected, is the significant growth of papers related to unconventional hydrocarbons.
Economical development of unconventional shale-gas reservoirs remains challenging, even if the petroleum systems are known, are laterally continuous, and usually require fewer delineation studies. Nevertheless, azimuthal-3D-seismic studies have a large potential in high grading low-permeability reservoirs with reliable fracture-network estimates. Despite the huge number of well locations that can be affected, significant seismic-cost reductions are needed to acquire basin-scale onshore seismic surveys routinely for unconventional resources. Seismic technologies for unconventionals typically assess fracture density or the efficiency of permeability-enhancing treatments on a smaller scale. Microseismic monitoring of hydraulic-fracture stimulations has experienced a steep rise in use and has improved the understanding of permeability enhancements through fracturing by close integration of seismologists, geologists, and geomechanical experts.
Modern 3D-seismic technologies are fundamental for reliable prediction of reservoir properties, pressures, and fluids and to enable robust safe-well planning. Whether one is drilling for infill or exploration, a degree of uncertainty remains. Calibrating surface seismic with real-time borehole measurements can bridge the gap between predrill planning and actual well operations effectively, which is especially valuable for challenging deepwater wells. Real-time measurements are an accurate and powerful tool to mitigate drilling risks related to borehole stability and pore-pressure prediction and to allow timely adjustments while drilling.
Complex seismic simulations are being used increasingly to study seismic-wave phenomena and to identify suitable acquisition geometries and processing schemes. New acquisition techniques, such as simultaneous shooting, enhance seismic-acquisition productivity significantly and enable a much denser sampling. 4D (time-lapse) seismic can be considered a mature technology for high-porosity offshore oil fields. Yet, the integration of 4D seismic in dynamic reservoir models is still an area of extensive research, and various approaches are discussed and trialed.
Seismic Applications additional reading available at OnePetro: www.onepetro.org
SPE 138864 “A Study of the Impact of 4D-Seismic Data on TSVD-Based Schemes for History Matching” by F. Dickstein, Universidade Federal do Rio de Janeiro, et al.
SPE 137919 “We Need to Rethink the Acquisition and Processing Parameters for Sea-Bottom Seismic in the Arabian Gulf” by Karl A. Berteussen, Petroleum Institute, et al.
SPE 138201 “Distance-Separated Simultaneous Sweeping: Efficient 3D Vibroseis Acquisition in Oman” by Jack Bouska, BP Oman.
Don't Look to the Big Shale Plays for Innovation in Horizontal Multistage Fracturing
Authors: Themig Dan 
Published: February 2015

Guest editorial
The good news is that there is plenty of innovation to talk about regarding step-change advances in horizontal multistage fracturing in many of the existing and emerging resource plays. The bad news is that you will not find these being applied in the Barnett Shale. While attending the SPE North Sea and European Area Stimulation Workshop (Berlin, Germany in September 2011) as well as the SPE Horizontal Well Completions in North America Shales Workshop (Scottsdale, Arizona in May 2011), it was evident that a number of emerging technologies are having a dramatic effect on improving ultimate recoveries in a number of plays. The interesting thing, however, is that these innovations are not being used in the so-called “legacy shale plays” (e.g., Barnett, Fayetteville) despite the fact that they are producing only break-even economics at today’s gas prices. You would expect to see aggressive innovation and experimentation in order to produce significant results in changing ultimate recoveries. The production results would suggest otherwise.
Results Speak for Themselves
At the Berlin workshop, a European producer who was investigating the Barnett to learn shale gas technology, presented a year-by-year production comparison for wells completed in the past five years. By looking at the average 24-month cumulative production from wells completed in each year, which is a pretty good gauge of ultimate recovery, it was evident that things are not improving. In fact, there was no upward trend at all in the data. Since investment continues to be significant in legacy trends, and international companies are investing billions of dollars to become players in shale gas technology, caution should be used in thinking that we have “arrived” in the Barnett.
At the SPE workshop in Scottsdale, which specifically targeted shale fracturing technology, the primary “innovation” to be used in the Barnett appeared to be moving from using one perforation cluster per stage a few years ago to three or four clusters in 2011. In essence, there was very little or no change to fracture placement and design. Based upon comments made at both workshops, there appears to be a limited under-standing of what can actually produce a step-change in recoveries.
What is a step-change? Increasing recoveries by 25%? 40%? More? The bad news is that you will likely not find process change in the Barnett or Fayetteville and, unfortunately, the industry still looks to the Barnett to understand “how shale gas is done.” So, if you are an investor who has poured billions of dollars into these plays, you may want to exercise caution in thinking that the operators in the Barnett have it figured out.
The good news, however, is that there is plenty of innovation going on in other plays that are producing step-changes in efficiencies, reducing water usage, decreasing the time required to fracture treat wells, and greatly increasing ultimate recoveries. The question is then, why are these innovations not being applied in the legacy shale plays?