bluuebunny/crossref_metadata_2025_split huggingface dataset:
Results of Dual Career Couple Survey
Authors: Sprunt Eve , Howes Susan 
Published: February 2015

Talent & Technology
One of the growing issues facing companies is managing employees who are part of a dual career couple. Traditionally, corporate policies were based on the assumption that even if one spouse worked, that person’s income would make up a relatively small fraction of the total household income. The spouse was assumed to be available to handle numerous house-hold responsibilities so the employee could focus on work. Much of the workforce is now juggling more complex personal logistics because both spouses are employed outside the home.
One of the objectives of the SPE Talent Council is conducting surveys and statistical analysis to highlight potential capability/expertise gaps and to identify possible solutions. To obtain information on the prevalence of dual career couples and the challenges facing them, SPE emailed a survey in May to 46,777 professional members, of which 5,570 responded. The results showed that dual career couples make up about half the workforce. Dual career couples will probably form a larger proportion in the near future, because those in such relationships are younger than those who are not. This article is a summary of the survey results, which are available in SPE-151971-MS at www.onepetro.org.
The largest number of survey responses, with similar percentages, came from the United States, Canada, and the United Kingdom, where SPE has the largest number of members. Members in 93 countries responded.
Of the total number of responses, 47% reported they were part of a dual career couple, 11% said they were previously part of a dual career couple, and 42% considered themselves to be single career. We also examined the results for two other groups. The first group was those in which the respondent said he or she is contributing between 33% and 67% of the household income, so that each partner is contributing at least a third. The second group was made up of those who reported contributing between 40% and 60% of household income. Of those who identified themselves as “dual career,” 47% said the lower-paid partner provides at least a third of the household income and 37% said that each partner provides nearly equal portions of the household income. Of all the survey responses, 22% came from couples where the minimum income contribution is a third and 17% came from those where the contribution is nearly equal. The days when the spouse’s salary could be viewed as providing an insignificant fraction of the household income that could easily be covered by a relocation bonus are gone.
Technology Focus: Field Development Projects (October 2011)
Authors: Rebelo Mauricio P. 
Published: February 2015

Technology Focus
From the time that an oil field is discovered by an exploratory well until it begins production of its first oil, the development-project team faces many technical decisions. Making correct choices is most critical to the project and is very challenging to the team, which must deal with several uncertainties.
Information acquisition is an important step in helping the team to understand the field and to make correct decisions. At this phase, a series of activities, including drilling appraisal wells, geology and seismic studies, reservoir simulations, and many others, are key factors that are necessary to achieve the most-accurate information from the reservoir. It is through such important information gathering and correct decision making that oil companies can define the appropriate development method for the oil field.
Optimizing costs and maximizing oil recovery are factors that will make field production more economically viable. A wrong decision may translate into a disastrous choice for the project. Oil-price uncertainty is another important part in this process that the companies must deal with. Well design and architecture, completion design, well stimulation, production facilities, and many other factors are important items to be defined to make a development project successful.
The papers selected for this feature are good examples of focusing on some of the factors just mentioned. It is interesting to read about different types of field-development projects in different areas. Specific project solutions and several studies and simulations used by the companies are shown in the articles and in the listed additional reading.
Field Development Projects additional reading available at OnePetro: www.onepetro.org
SPE 137220 • “GOM Deepwater-Field-Development Challenges at Green Canyon 468 Pony” by Michael H. Weatherl, Hess Corporation. (See JPT, April 2011, page 70.)
OTC 21583 • “Field-Development Planning and Floating-Platform Concept Selection for Global Deepwater Developments” by Richard D’Souza, Granherne, et al.
SPE 133874 • “A Completions Guidebook to Shale-Play Development: A Review of Successful Approaches Toward Shale-Play Stimulation in the Last Two Decades” by K.K. Chong, Halliburton, et al.
Ultradeepwater-Subsalt-Reservoir Characterization: Integrated Multiscenario Development Planning
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142280, ’Ultradeepwater- Subsalt-Reservoir Characterization: An Integrated Multiscenario Approach for Development Planning,’ by Olivier Pippi, SPE, Statoil ASA (formerly with BP plc), Mike Mayall, Mike Chandler, SPE, Tim Dodd, Paul Reid, and Paul Taylor, BP plc, prepared for the 2011 SPE Europec/EAGE Annual Conference and Exhibition, Vienna, Austria, 23-26 May. The paper has not been peer reviewed.
Subsea development of clustered deepwater subsalt fields is challenging, technically and economically. With the high cost of appraisal wells, the industry tends to rely on seismic technology, pushing the limits of imaging and characterizing the reservoir by use of seismic attributes. A fully integrated approach that uses all available data should be followed to describe the uncertainty fully and to make an optimized business decision. This work shows a systematic method to integrate information available from a limited data set to validate the description of the field and to perform a full risk and uncertainty analysis supporting the field-development strategy.
Introduction
Many exploration plays in deepwater basins around the world involve structural closures associated with stratigraphic-trapping elements that are above or against salt diapirs or canopies. Below these often-large salt bodies, seismic imaging can be impaired significantly, which makes the crest of the structure particularly complicated to map. Updip volumes that are close to the salt can be difficult to describe with confidence, yielding large uncertainty about hydrocarbon volumes in place.
Reservoir faulting induced by the movement of the salt over geological time introduces significant structural complexity. This complexity adds to common stratigraphic and depositional complexity of deepwater reservoirs deposited in turbidite slope settings. Deepwater turbidite reservoirs can be large erosional channels (typically 1 to 3 km wide and 50 to 200 m thick) or can be sheet-like sands (typically 1 to 5 km wide and 5 to 30 m thick) with various degrees of channel amalgamation. Each type of reservoir poses specific development challenges in terms of continuity and connectivity.
Multiscenario Risk and Uncertainty Analysis
Given the structural complexity of the field, the wide range of oil-in-place estimates results in making risk and uncertainty analysis difficult to address at the same time. A project close to sanction would have a firmer resources-in-place definition before making a decision. Alternatively, the decision would have flexibility to be phased in over a certain time as new production data become available.
Technology Focus: Tight Reservoirs (October 2011)
Authors: Kubala Gregory 
Published: February 2015

Technology Focus
Multistage fracturing of long horizontal wells remains the cornerstone for maximizing reservoir contact and drainage in low-permeability reservoirs. Operators are no longer satisfied with the “standard” design methodology of the past. Leading exploration and production companies are beginning to adopt a well-by-well design strategy for drilling and orienting the lateral to optimize the multistage fracturing treatments.
As experience continues to grow, engineers develop increasingly more-accurate models and workflows for exploration, development, and production of tight hydrocarbon-bearing reservoirs. Geomechanics, petrophysics, and geophysics are coupled with microseismic, fracture-treatment-pressure signatures, and production data to place, drill, and perforate wells better, all in an effort to maximize production derived from multistage fracture-stimulation treatments.
The best effective fracture half-length is not achieved automatically just by putting away millions of pounds of proppant with millions of gallons of water. Perforation strategies and pumping techniques do affect proppant placement for enhanced fracture conductivity. Hydraulic-fracture conductivity also is influenced by near-wellbore and far-field issues. Several papers indicate that production may increase significantly if actions are taken to address these issues.
As our industry enjoys the privilege of developing these reservoirs, it is incumbent upon us to meet environmental challenges, comply with regulatory requirements, and ensure public trust.
Tight Reservoirs additional reading available at OnePetro: www.onepetro.org
SPE 144279 • “Shale-Gas Developments in North America: An Overview of the Regulatory and Environmental Challenges Facing the Industry” by S.L. Sakmar, University of San Francisco Law School.
SPE 141597 • “Polymer Chemistry Improves Productivity in Tight Gas Hydraulic Fracturing” by Rick Hutchins, SPE, Schlumberger, et al.
SPE 142040 • “Optimization of the Design of Transverse Hydraulic Fractures in Horizontal Wells Placed in Dual-Porosity Tight Gas Reservoirs” by S.E. Gorucu, Pennsylvania State University, et al.
SPE 143304 • “The Effect of Fracture-Face Matrix Damage on Productivity of Fractured Wells With Infinite and Finite Fracture Conductivities in Shale-Gas Reservoirs” by Boyun Guo, University of Louisiana at Lafayette, et al.
SPE 140555 • “Design of Multiple-Transverse-Fracture Horizontal Wells in Shale-Gas Reservoirs” by Bo Song, Texas A&M University, et al.
Integrating New Seismic Technology and Regional Basin Geology Now a Must
Authors: Dribus John 
Published: February 2015

Management
Since the discovery of the giant Tupi-Lula pre-salt complex in the Santos Basin of Brazil, explorers have been integrating new seismic technology advances with the fundamentals of regional basin geology to extend the pre-salt play across the Atlantic margin into deep waters and below the salt off the west coast of Africa. In 2005, Petrobras drilled a wildcat well on the Parati prospect in the deep waters of the Santos Basin, and encountered condensate gas below a thick layer of salt. The following year, Petrobras and its partners, BG Group and Galp Energia, announced that the Tupi wildcat, drilled to 16,060 ft in almost 7,000 ft of water, flowed at 4,900 B/D of sweet 30°API crude oil, 0.7 sulphur content, and 6.6 MMcf/D gas on a ⅝-in choke. This confirmed that a new geologic play had been discovered below the salt. Over the next few years, exploration efforts continued in this new pre-salt play, resulting in additional discoveries in the Santos and to the north in the Campos and Espirito Santo basins.
Agencia Nacional do Petroleo (ANP) studies suggested that the charge and accumulation models for this new pre-salt cluster area of the Santos Basin contained reserves exceeding 30 billion bbl and possibly as large as 60 billion bbl of oil reserves. Though the thick layers of salt above the oil accumulations create challenges in seismic imaging and exploratory drilling, the salt has also served, through geologic time, as a superb seal that allows thick columns of oil to accumulate and be preserved.
Many exploration companies have already constructed regional geologic and plate tectonic models that recognize that these world-class pre-salt hydrocarbon accumulations off the east coast of Brazil may have counterparts on the conjugate margin of the Atlantic Basin in the deep waters offshore Congo, Gabon, Angola, and Namibia. A geologic model from Cobalt International shows a cross section of the Atlantic rift system that predicts similar geology between the two margins (Fig. 1).
Early-Life Field-Development Optimization of a Complex Deepwater Gulf of Mexico Field
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 22252, ’Early-Life-Cycle Field-Development Optimization of a Complex Deepwater Gulf of Mexico Field,’ by Patrick F. Angert, SPE, BP Exploration; Obiajulu J. Isebor, SPE, Stanford University; and Michael L. Litvak, SPE, BP Exploration, prepared for the 2011 Offshore Technology Conference Brasil, Rio de Janeiro, 4-6 October. The paper has not been peer reviewed.
A complex deepwater Gulf of Mexico field contains several stacked hydrocarbon-bearing intervals charged with volatile oil or rich gas condensate. Well locations, drilling schedule, and reservoir units into which wells will be initially completed and then later recompleted were optimized, maximizing net present value (NPV) while matching field-development constraints. Potential well locations and recompletion locations in geologically justified areas were evaluated. Drilling-rig pace and order and associated project and drilling economic constraints have been considered. BP’s Top Down Reservoir Modeling (TDRM) Option Evaluation (OE) technology has been extended to cover the simultaneous optimization of well completions and recompletions in reservoirs containing multiple stacked pay.
Introduction
Assisted-history-matching technologies have proved extremely useful for identifying multiple geologically plausible matches of historical production and surveillance data within existing fields. Assisted field-development optimization, although slightly newer, is nevertheless proving extremely useful in the identification, categorization, understanding, and ranking in economic and recovery terms of the multitude of possible development scenarios that could be implemented to produce oil, gas, or condensate from a field.
These technologies couple with existing full-physics reservoir simulators and rely on search-and-optimization algorithms such as genetic algorithms, Monte Carlo, or other optimization/search routines.
Typically, tens of thousands of possible development scenarios are generated in search of a much smaller set that meets all of the initial criteria specified while achieving higher overall project NPV and recovery. High potential cases are then investigated further, and, ultimately, a final development scenario is selected and refined further as a project progresses toward a final investment decision and commitment of project development capital.
Field Background
For the field under investigation, rich-gas-condensate and volatile-oil accumulations sit in a water depth greater than 6,000 ft. The upper hydrocarbon-bearing intervals occur below approximately 24,000-ft true vertical depth subsea (TVDSS) and extend to greater than approximately 29,000-ft TVDSS. The highest initial pressure of a hydrocarbon-bearing interval is approximately 20,000 psia.
Infrastructure Sharing Creates Value for Brazilian Deepwater Offshore Assets
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 23004, ’Infrastructure Sharing: Creating Value for Brazilian Deepwater Offshore Assets,’ by Daniel C. Pedroso, SPE, Demetrius C. Abdala, and Luiz A.G. Pinto, Petrobras, prepared for the 2012 Offshore Technology Conference, Houston, 30 April- 3 May. The paper has not been peer reviewed.
Investments in infrastructure for deepwater production require a significant scale for achieving minimum economic returns. The infrastructure is normally planned to accommodate the peak production, and many of the assets may not be recovered or reused. Therefore, a significant spare capacity may arise in such assets. The use of spare capacity by other fields is a typical process in which both parties, the producer and the receiving facility, will benefit.
Introduction
The development of deepwater offshore production is characterized by high capital expenditure (CAPEX), significant economy of scale, and, in many cases, the complete technical unfeasibility of reuse of the materials and equipment.
Production infrastructure, when located in deepwater, is normally initially installed for the exclusive use of a specific field that justifies a standalone development approach. Processing, compressing, and export capacities are designed to attend peak production. Therefore, some spare capacity will appear at some point, which may be constrained by the amount of water that is handled in the unit.
Evolution of the Production Infrastructure in Campos Basin
The production in the deepwater Campos basin of Brazil has guided the exceptional growth of Petrobras in the last two decades, providing the technological, human, and financial resources that enabled the discovery of the giant presalt fields in Santos basin, currently under development. Petrobras’ net daily production in the Campos basin (oil and gas) reached 1 million BOE (annual daily average) in 2000, 1.5 million BOE in 2004, and 1.8 million BOE in 2010 (1.66 million bbl of oil). Other companies produce approximately 150,000 BOE/D. The Campos basin is Petrobras’ main producing area, currently producing 83% of the companys total output in Brazil. This production comes from 43 fields, including eight large oil fields in deep and ultradeep water, many of them developed using multiple production units. Petrobras’ proved oil reserves in the Campos basin are on the order of 10.7 billion bbl. The infrastructure already installed is extensive: Petrobras alone operates 40 floating production systems, 14 fixed platforms, and 6680 km of pipeline and flexible pipes in the area.
More recently, the activities began to focus on carbonate reservoirs below the presalt layer in the Sao Paulo plateau in water depths from 2000 to 3000 m. Several discoveries have occurred recently below the presalt in areas that are already in concession and are in production, sometimes with an existing production unit that faces the challenge of maintaining the economical feasibility under a low-oil-/high-water-production profile.
Technology Focus: Sand Management and Frac Pack (October 2012)
Authors: Azeemuddin Mohammed 
Published: February 2015

Technology Focus
Production from challenging environments is fast becoming the norm for the oil and gas industry. We increasingly drill long horizontal sections in high-pressure/high-temperature reservoirs, deep and ultradeep water, and unconsolidated, depleted, and narrow-margin fields. With the cost of each well often exceeding USD 250 million, there is very little margin for error in designing and placement of the completions to avoid sanding-related issues and costly workovers.
Novel materials such as light and ultralight proppants and shaped memory polymers, cutting-edge technologies, and robust hardware are all important elements for meeting the ever-growing challenges. Meticulous planning, bench testing, and field validation form a prerequisite for cost-effective and safe execution. Effective research and development (R&D) efforts and close cooperation among academia, R&D services, and industry experts (operators) pave the way for a technically successful and economically viable exploitation of our depleting reserves. One should also spend the time and effort to improve understanding of rock behavior in its in-situ stress environment, as well as accurate characterization of the unique stress conditions in the field. A mechanical Earth model satisfactorily calibrated to the drilling events and geologically consistent with the stress environment is often required to model and test various possible sand control methods and their economics accurately.
Despite these efforts, it may not be possible to completely avoid sand production and its detrimental effects. Detecting and monitoring sand production with downhole monitoring tools, knowing the limits of effective sand management, and staying within those limits can be practical means for safe and long-term economic field development.
The selected papers highlight areas of current research focused on developing solutions and proper planning of safe hydrocarbon exploitation. Other interesting papers involving field applications and case studies, in no way less important, have been identified for additional reading.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 146650 Mechanical Modeling of Shape-Memory Polyurethane Foam for Application as a Sand-Management Solution by Cem Ozan, Baker Hughes, et al.
SPE 147044 The Use of Slotted Expandable Liners in Multizone Openhole Frac Packs: A New Completion Concept by David Mason, BP, et al.
SPE 146721 Ceramic Screens, an Innovative Milestone in Sand Control by S. Mussig, Maersk Oil, et al.
New Uses Keep Emerging for a Deceptively Simple Pump
Authors: Rassenfoss Stephen 
Published: February 2015

Progressing Cavity Pumps
Progressing cavity (PC) pumps have been around too long to be a young technology, but it is still an emerging one.
The history of this rapidly growing form of artificial lift is a study in how a community of users can continue to find ways to adapt a seemingly simple machine that can have a complicated relationship with a reservoir. What started as a better option for pumping cold, heavy, sandy crude in Canada has been adapted for high-volume production of heavy crude in Venezuela, for lifting medium-weight oil mixed with things that other pumps cannot handle well, and pumping water out of Australian coal seams to initiate natural gas production from the thousands of wells in the huge deposits.
All-metal versions are beginning to appear in heavy oil fields, after a decade of development and testing to prove they could work at temperatures far beyond what standard PC pumps could handle.
Pushing the capabilities of these pumps, which cannot reliably handle light oil, will require a new generation of elastomers. This will likely require oil and gas industry users to push chemical makers to develop elastomers with capabilities that go beyond the needs of their biggest customers, auto parts makers who use them for tires and other car components.
Several companies recently have begun trying to persuade users to turn to PC pumps powered by permanent magnetic motors downhole rather than relying on rotating rods powered by sur-face units. The advocates of downhole power, which has been a small part of the business, say it can allow more effective PC pump use and reduce tubing damage caused by long rod strings, which can also come apart.
Innovative new pumps are appearing, with some using the usual materials in surprising ways.
“The manufacturing of PC pumps is growing and I think everybody is trying to push the envelope a lot now,” said Shane Latoski, product manager of Oil Lift Technology, which is part of Dover Corporations’ Norris Production Solutions operation. “There are some interesting things coming through.”
The company is in the middle of a rapidly growing business—PC pump makers are also benefiting from the strong sales of mud motors, which are the different use of the original design. The growth of the PC pump business is an example of the value of adaptive reuse.
While emerging technologies are associated with scientific breakthroughs, mature businesses can find and profit from emerging opportunities that grow out of their normal business, said Pradeep Anand, president of Seeta Resources, a business consultant who has advised companies seeking such opportunities.