bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Improvements to Deepwater Subsea Measurement
Authors: Carpenter Chris 
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 25686, “More Improvements to Deepwater Subsea Measurement: Overview,” by W. Letton, Letton Hall Group; J.M. Pappas, Research Partnership To Secure Energy for America; and J. Shen, Chevron, prepared for the 2015 Offshore Technology Conference, Houston, 4–7 May. The paper has not been peer reviewed.
In an effort to develop new measurement technologies for ultradeepwater oil and gas production, the US Department of Energy’s National Energy Technology Laboratory under the Research Partnership To Secure Energy for America (RPSEA) has initiated a new project. This project, titled More Improvements to Deepwater Subsea Measurement, has addressed those gaps that were identified by an earlier RPSEA project as the most pressing for multiphase-flow measurement.
Introduction
Approximately 15 years ago, as offshore production in the Gulf of Mexico and elsewhere moved off the continental shelf and into truly deep water, it became apparent that methods of measuring the flow of oil and gas would have to change in a significant manner. Not only did formidable technical challenges exist in performing production tests on wells that were many miles away in 1000 m or more of water, but the economics of installing test lines to perform such tests simply was not acceptable. Production from many wells would be commingled, and one of two alternatives would have to be chosen: Either a clever way of testing well rates from the combined flow would be developed, or each well’s rate of production would be measured before commingling.
Discussion History. Past efforts of RPSEA and others to research improving deepwater exploration-and-production operations are detailed in the complete paper. At the conclusion of one such RPSEA project, running from 2008 to 2011, several leaders in a joint-industry project ( JIP) that had supported that effort expressed an interest in a followup RPSEA project to refine certain results from the first project, and to investigate those areas where it was felt there were still questions needing answers. Consequently, a new proposal was submitted for RPSEA’s consideration, resulting in the new RPSEA project: 10121-4304-01, More Improvements to Deepwater Subsea Measurement. The following topics were identified:
Deepwater fluid sampling
Deepwater meter-verification technology
Early kick detection
Downhole differential-pressure-sensor development
Virtual-flowmeter evaluation
Detection of meter fouling
Each of these topics could have qualified as a project on its own, but the fact that the common thread of measurement ran through all, requiring the same kind of expertise in investigators, suggested that grouping the various parts under a single RPSEA project, managed by those experienced in measurement, made good sense. Therefore, this was the approach taken once again.
Shale Completions Improve, Despite Shrinking Number of New Wells
Authors: Jacobs Trent 
Published: January 2017

Shale Completions
Two places that illustrate the mounting challenges facing the shale business are the Bakken Shale in North Dakota, where the number of working rigs is one-third what it was a year ago, and the Fayetteville Shale in Arkansas, where there are no more working rigs.
Steve Mueller, the outgoing chairman of the board and former chief executive officer of Southwestern Energy, the company that discovered the Fayetteville Shale, noted how the current environment has made it harder to drive innovation forward even as it becomes more important than ever.
“How in the world do I learn at the speed I was learning at before when I am not drilling as many wells, when I am not doing as many fracs, and when I don’t have as much money?” he said. “And the conclusion I come to is that we have got to do it a different way and we have got to do it a lot faster.”
Mueller spoke in February before a room of engineers and service providers at the SPE Hydraulic Fracturing Technology Conference in The Woodlands, Texas, where some of the innovations spurred by the need to change were presented. But because so many companies have laid down so many rigs, it will take a significant price recovery before the latest advancements and efficiencies make a big impact on the shale sector.
Getting More From More
A good example of a company executing a strategic retreat is Hess Corporation. In 2014, the company had 17 rigs running in its Bakken program. At the start of this year, that number was two. Despite the major pullback, the company has moved forward on two key completions strategies: increasing the number of stages from 35 to 50 and switching to a cheaper, and more effective, fracturing fluid system.
No-Damage Stimulation By Use of Residual-Free Diverting Fluids
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 177495, “No-Damage Stimulation Based on Residual-Free Diverting Fluid for Carbonate Reservoir,” by Y. Shi, X. Yang, F. Zhou, Y. Gao, S. Lian, X. Li, and X. Han, Research Institute of Petroleum Exploration and Development, CNPC, prepared for the 2015 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 9–12 November. The paper has not been peer reviewed.
Horizontal wells and acid stimulation are essential technologies for the development of complex carbonate reservoirs. However, conducting effective stimulation in horizontal wells with long intervals is extremely difficult because traditional acid systems can flow only into the high-permeability formations, leaving the damaged formation untreated. This paper studied three residual-free fluid systems for acid treatments and fracturing in order to develop no-damage or reduced-damage and highly effective stimulation techniques for long-interval wells.
Introduction
Horizontal wells are essential for the development of carbonate reservoirs in China. However, horizontal wells always have long intervals, so they are extremely difficult to stimulate.
The fluid systems used are a critical aspect of high-efficiency stimulation. Traditional acid systems, which do not have diverting capabilities, can flow only into the high-permeability formations, leaving the damaged formation untreated. That is why long-interval wells with high heterogeneity need to be treated by a diverting acid system.
A new diverting acid system should have the following characteristics: The capability to reduce the acid/rock reaction rate; a diverting performance to achieve uniform stimulation in a carbonate reservoir with high heterogeneity; and use of clean chemical additives to eliminate or limit damage.
This paper analyzes three clean fluid systems for acid treatment and fracturing. The no-damage stimulation systems considered are a temperature-controlled deep-diverting acid system (TCA), a pH-controlled self-diverting acid system (DCA), and a fracture-reorientation technology using degradable fiber (RDF).
TCA
Diverting Mechanism of TCA. The TCA system is similar to ordinary gelled acid during pumping. The gelling agent can dissolve in water in a short time, reducing the frictional resistance of the system dramatically and making it easy to prepare and pump. At formation temperature, the system has a high viscosity to ensure diverting and retarding performance. After the acid fracturing treatment, the viscosity of the spent acid decreases in order to flow back easily and leave no damage in the formation.
Breaking from the Norm to Reach Marginal Offshore Fields
Authors: Jacobs Trent 
Published: January 2017

Marginal Offshore Fields
One could argue that now is not the time to discuss how marginal or stranded offshore fields can be effectively monetized. After all, even in the good times the offshore sector showed that it had little appetite for small-scale developments; their risk-reward ratio is usually not viewed as worth the effort.
On the other hand, going big has not exactly worked out for the offshore sector in recent years. Too many headline projects have suffered major cost overruns or missed production targets.
And thanks to low oil prices, most of the recently completed projects that managed to stay on budget are now operating at a significant loss. On top of all that, the number of commercially viable offshore discoveries has been shrinking each of the past few years.
As the challenges continue to mount, a number of technology developers are hoping to rewrite the offshore playbook. Much of their work is focused on developing cheap ways to access the marginal assets that often lie just beyond the reach of existing facilities. Some of the more radical ideas involve developing futuristic and nimble technologies that could drastically reduce the physical capital required for green-field projects.
A company in Norway thinks it can do this by drilling record-long wells from aging platforms for a fraction of the cost it takes to use floating rigs or subsea production systems. Another Norwegian- born firm is working on a standalone drilling robot that will burrow thousands of feet into the subsurface where it will appraise a prospective reservoir and then monitor it for several years afterward.
Others are pushing for simpler solutions that have less to do with emerging technology and instead center on persuading oil companies to change how they develop their subsea properties. Among them is a call to build deep water floating facilities with spare capacity to handle unplanned field expansions. A proposal for shallow water argues that operators should use fixed-leg platforms that can be floated away and reused in multiple fields.
While these ideas do not answer all of the problems facing the offshore sector, nor do they apply to every type of field, they address the primary sources for spiraling costs. Using far less steel and far fewer people could allow subsea assets to start delivering positive earnings.
Increasing Efficiency, Safer Operations Key Themes at OTC
Authors: Parshall Joel , Jacobs Trent , Rassenfoss Stephen 
Published: January 2017

Conference review - 2016 OTC
Despite the downturn in the oil and gas industry, more than 68,000 experts and leaders gathered from across the world in Houston for the 2016 Offshore Technology Conference (OTC) in May. The number of attendees, from 120 countries, put this year’s OTC among the top 15 in attendance in its 48-year history.
“As it has since 1969, the world came to OTC to make critical decisions, share ideas, and develop business partnerships to meet global energy demands,” said Joe Fowler, 2016 OTC chairman. The conference included 11 panel sessions, 24 executive keynote presentations, and more than 325 technical paper presentations.
Increasing efficiency while ensuring safe operations was a key theme at this year’s conference. Sessions covered new technologies that not only reduce costs to the operator but enhance the overall safety of the operations; cost-effective advances in well cementing technologies; and use of RFID to precisely track drillpipe.
Subsea Processing
Panel sessions covered a variety of industry issues, including the value of subsea operations. Moving oil/water separation equipment from platforms to the seabed looks inevitable, but based on the current rate of adoption, it may require a long-term outlook. Out of the 5,000 wells with subsea completions, only five have used some variety of separation, whether it is separating water from oil, gas from liquids, or treating seawater before it is injected into a reservoir.
A panel made the case for why separators are a better option in deep water than lifting water a mile or more, processing it, and pumping it back down to the bottom for injection into the ground. “It is going to happen,” said Jeff Jones, senior subsea systems consultant for ExxonMobil. “We will get back to it.” Jones referred to subsea separation in the past tense because it has been a while since the five projects, eight if you include some smaller units used for pilots, have gone into service.
“It is not as dead as you think,” said Don Underwood, director of subsea processing for FMC Technologies. “We are in a world where, perhaps, operators cannot go forward with green-field projects,” but still need to find ways to add production to make up for declines in older wells.
As for what will turn the inevitable technology into a practical option, the one-word answer is cost. Statoil, which has been a major supporter of moving operations subsea, has said that a 50% cost cut is needed, while Petrobras has put that number at 30%.
“There has been significant movement in that direction,” Underwood said. “For one, prices have been lowered dramatically,” while designs have shifted from huge units to “lower-cost, compact technologies” that can be added as a cheaper alternative to drilling.
Modeling of a Complex Reservoir Where the Normal Modeling Rules Do Not Apply
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 169369, “Integrated Modeling of a Highly Structural and Complex Reservoir Where the Normal Modeling Rules Do Not Apply—Cerro Fortunoso,” by Anthony Thompson, SPE, Abel Garriz, Gaston Manestar, SPE, Griselda Vocaturo, Vanesa Consoli, and Pablo Giampaoli, YPF, prepared for the 2014 SPE Latin American and Caribbean Petroleum Engineering Conference, Maracaibo, Venezuela, 21–23 May. The paper has not been peer reviewed.
With the easy conventional oil in Argentina having been produced, one remaining way to find new oil in existing fields is to convert fields from primary or secondary production to secondary or tertiary production, respectively. For the Cerro Fortunoso field, the high costs required to develop the field, combined with an ambiguous log response that suggested that sand was predominantly disconnected, resulted in secondary production not being implemented. To reduce the risk, a waterflood pilot was necessary to demonstrate that waterflooding has potential and to provide water-injection and production data to constrain the history-matching process.
Introduction
Fig. 1 shows the location of Cerro Fortunoso in Mendoza province, approximately 1200 km southeast of Buenos Aires. Most large fields in Mendoza province were exploited by waterflood decades ago. For waterflooding not to be initiated, the nature of the reservoir had to be unclear or the capital expenditure required had to be high. In the case of Cerro Fortunoso, a substantial investment is required to cover the cost of drilling infill wells and for the construction of a pipeline to provide injection water from a river 15 km away.
To minimize the risk associated with converting the field to waterflooding, an integrated study was sanctioned that aimed to characterize the field initially and then to determine if waterflooding would, in fact, be economically viable.
Structural-Model Construction
Usually, the first step in the construction of a structural model is to extract a surface from a seismic marker. Unfortunately, in Cerro Fortunoso, the presence of a significant thickness of igneous rock and high-angle flanks causes high noise and attenuation, respectively, on existing 2D-seismic data and makes completing a 3D survey a fruitless exercise. Without 3D seismic, the structural model was constructed on the basis of data from both surface outcrops and subsurface well data. This was a challenge because Cerro Fortunoso is in a complex structural environment and the fold geometry was shown to vary significantly along the strike of the field.
Operational Risk: Stepping Beyond Bow Ties
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 174995, “Operational Risk: Stepping Beyond Bow Ties,” by D. Fraser, SPE, J. Braun, and M. Cunningham, Argonne National Laboratory; B. Marple, Chevron; D.D. Moore, SPE, Marathon; A. Sas-Jaworsky, SPE, SAS Industries; and J. Wilson, Transocean, prepared for the 2015 SPE Annual Technical Conference and Exhibition, Houston, 28–30 September. The paper has not been peer reviewed.
This paper presents the multiple-physical- barrier (MPB) approach to operational (or process) risk, an extension of the common bow-tie technique for identifying risk. Bow ties identify a variety of different types of barriers and help communicate safety principles that link causal factors and subsequent actions to a specific event. By narrowing the focus to physical barriers and by developing success paths that enable each barrier to perform its safety function, the MPB approach moves further toward a systematic approach to operational-risk management.
Introduction—Operational Risk, Bow Ties, and Physical Barriers
Operational Risk. One of the more elusive issues in the upstream oil and gas industry is the understanding of process safety or process risk—especially how it overlaps with industrial (or personal) safety—and the types of tools needed to assess and manage it. An important part of this hinges on the role that barriers play in the analysis and what constitutes a barrier. Some companies consider training to be a barrier, others consider certain meetings to be barriers, and still others consider safety procedures themselves to be barriers. Indeed, there is scarce practical agreement between companies as to how process risk is assessed, managed, and communicated. As a result, there can be similarities, but, ultimately, no two process-risk assessments from different companies look the same.
Several different barriers are shown in the bow-tie diagram in Fig. 1. Barrier types there include the well-control program, mud checks, fill-ups, and escalation barriers.
Bow-Tie Analysis. Bow-tie analysis has been widely used in the offshore oil and gas industry as a technique for communicating safety issues and safety control measures. Bow-tie analysis is event based; it seeks to tie causal factors and subsequent actions to a specific event, such as a kick. Bow-tie diagrams help teams better understand the sequences that can lead to serious process or operational risks. They also identify mitigating actions that can be taken to reduce the consequences of a major event.
The MPB Approach—A Pathway to Success
The MPB approach was developed with the help of collaborations from the upstream oil and gas industry. It takes a step beyond bow ties toward a more-direct and -systematic understanding of operational risk so that operators can design their operations to be successful. In so doing, risk is systematically identified and evaluated and can be incorporated into the management system to help ensure the safety of offshore operations.
Completion and Well-Spacing Optimization for Horizontal Wells in Pad Development
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 180956, “Completion and Well-Spacing Optimization for Horizontal Wells in Pad Development in the Vaca Muerta Shale,” by M. Suarez, SPE, YPF, and S. Pichon, SPE, Schlumberger, prepared for the 2016 SPE Argentina Exploration and Production of Unconventional Resources Symposium, Buenos Aires, 1–3 June. The paper has not been peer reviewed.
In organic shales, hydraulic fracturing is important for optimizing the production of horizontal wells. For a standalone lateral, the propped surface should be maximized to increase production. In the case of a pad, well spacing is an additional factor. Competition for production between laterals of a given pad should be minimized and is the result of both well spacing and hydraulic-fracture design. A numerical model coupling an explicit description of the hydraulic-fracture geometry and reservoir simulation is proposed to evaluate production interference.
Introduction
Well Spacing. One of the more critical questions that any asset team must consider concerns well spacing when designing the development plan for a new field. Well spacing defines the total number of wells, the drilling and completion schedule, and the field-production curve. The ultimate decision relies on economic analysis, balancing the expected ultimate recovery against capital and operational expenditures.
This work focuses on methods to evaluate different well spacing and on how to reduce the range of uncertainty in the development of the Vaca Muerta play.
Well-Spacing Evaluation. Well spacing depends on geomechanics, petrophysics, stimulation design, hydraulic-fracture geometry, and reservoir fluids. These factors are combined by use of numerical simulation to study their effects on the well spacing. The following are some of the methods that are applied to define possible well spacing.
Analogs. Using analog methods requires an older field already in development with similar rock and fluid quality, structural complexity, well architecture, and hydraulic-fracture stimulation. The analog approach leads to large uncertainties if any of these parameters are not within the same range or if the older analog field does not have sufficient statistical representation.
Simple Reservoir Description Without Explicit Hydraulic-Fracture Description.
The first step in simulation is to start with a simple reservoir description in which each property is uniform (porosity, permeability, and fluid saturations). The reservoir model is then coupled with an analytical or numerical production simulator. This kind of approach is appropriate for a field with minimal information. The hydraulic fractures are represented as parallel planes that intersect the wellbore. Hydraulic-fracture properties are kept constant over their whole surface and along the lateral.