bluuebunny/crossref_metadata_2025_split huggingface dataset:
Automated Alarms for Managing Drilling Pressure and Maintaining Wellbore Stability
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146298, ’Automated Alarms for Managing Drilling Pressure and Maintaining Wellbore Stability - New Concepts in While-Drilling Decision Making,’ by Andreas Sadlier, SPE, Chris Wolfe, SPE, Mike Reese, SPE, and Ian Says, SPE, Baker Hughes, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed.
With the increased complexity of wells being drilled, significant geologic uncertainty may be encountered during wellbore construction. Uncertainty can take the form of unplanned drilling events such as kicks, lost circulation, and borehole-stability problems. A more proactive effort to predict and identify trouble zones in real time could lead to a substantial reduction in nonproductive time (NPT) and safety risks. Computer systems can automate the filtering and distribution of relevant information to personnel quickly for more-rapid assessment of a situation.
Introduction
To assess and analyze the current risks, field engineers are tasked with monitoring various measurements and data feeds while drilling and, if potential problems occur, making recommendations for corrective actions. With an increasing volume of more-complex data available in real time, how can engineers analyze relevant information effectively and in a timely manner to mitigate risk? One way is to leverage the power in modern computer systems. Software automates the filtering and distribution of relevant information to personnel quickly for rapid assessment of a current drilling challenge. For example, in a pressure-management (PM) operation, alarms can be activated automatically to provide quick warnings on the basis of equivalent-circulating-density (ECD) measurements (in the context of the mud-weight window) and to indicate potential hazards. These alarms could help filter and interpret complex real-time data sets quickly, without relying solely on the experience of the individual pressure engineer to detect a possible drilling risk. A PM and wellbore-stability (WBS) alarming system was designed to reduce complexity and facilitate PM/WBS decision making in near real time.
Background
During drilling, the safe-mud-weight window ranges from the pore-pressure gradient (on the low end) to the fracture gradient (on the high end). The goal of real-time PM involves selecting and maintaining the downhole drilling-fluid pressure within the drilling-mud-weight window to reduce drilling NPT (drilling NPT attributed to pore-pressure and wellbore-instability issues is approximately 40%). To reduce this type of NPT effectively, the use of real-time PM engineers is recommended at the rigsite or from a remote monitoring center.
Technology Focus: Well Testing (February 2012)
Authors: Angeles Renzo 
Published: February 2015

Technology Focus
The value of information has a ubiquitous and sometimes pervasive role in modern well testing. From exploration to field management to surveillance, well-test practitioners deal with a wide array of measurements (e.g., pressure, flow rates, temperature, and fluid analysis) that, more often than not, encompass large amounts of data. This is particularly true for long-term-production-data analysis of established fields, and one can argue the same for any current pressure-transient analysis that also has benefited from improved and more-robust data-acquisition available today. Likewise, dynamic information through downhole testing equipment can be acquired in real time—wirelessly and at sampling frequencies that were not possible only a decade ago.
Yet what seems to be a relative abundance of data often is challenged by the complex environments in which we operate and by our need to assess its value against associated costs and business risks. One way to look at this is under the premise that, while “perfect” information is beneficial to have, it also is costly to acquire and economically inefficient. Is there a unique answer in our choice of type curves, material balance, or specialized graphs? Should we account for multiphase flow or rock compaction? More importantly, what is the value of the next-best substitute for the information we require? And can this substitute information still allow us to meet our testing objectives? Herein lies the delicate balance between our choices of risk and uncertainty, which brings us to the message of this feature: We should not look for data-rich, but information-rich, content that meets our testing needs.
The papers selected for this feature describe exciting advances and opportunities in well testing. They also show that the proper use of advanced techniques can lead to maximizing the value of the information at hand, even in hostile and unconventional situations.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 143592 Assessment of Rate-Dependent Skin Factors in Gas-Condensate and Volatile-Oil Wells by A.C. Gringarten, SPE, Imperial College London, et al.
SPE 146450 3D Multiphase Streamline-Based Method for Interpretation of Formation-Tester Measurements Acquired in Vertical and Deviated Wells by Hamid Hadibeik, SPE, University of Texas at Austin, et al.
SPE 142818 Application of IFOT in Tight Gas as a Reservoir-Surveillance Technique by E. Pinto, BP plc, et al.
Spatial-Feature Identification and Parameter Estimation From Pressure-Transient Tests
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142996, ’Grid-Based Inversion Methods for Spatial-Feature Identification and Parameter Estimation From Pressure-Transient Tests,’ by K.L. Morton, SPE, and R.J. Booth, Schlumberger; M. Onur, SPE, Istanbul Technical University; and F.J. Kuchuk, SPE, Schlumberger, prepared for the 2011 SPE Europec/EAGE Annual Conference and Exhibition, Vienna, Austria, 23-26 May. The paper has not been peer reviewed.
Three grid-based inversion methods for estimating formation parameters and for spatial geological-feature identification based on pressure-transient-test (PTT) data from multiple-well locations were investigated. The first two methods use efficient adjoint schemes to determine the gradient of the objective functions. The third method uses ensemble Kalman filtering (EnKF) for data assimilation. With these methods, the existence and location of many subseismic features, such as strong spatial permeability variations, faults, fractures, and pinchouts, may be determined by use of exploration and production data.
Introduction
PTTs are used to determine the productivity of a well and the properties of the formation (reservoir) on the basis of downhole and/or surface pressure and flow-rate measurements. The main steps for interpretation are:
Model identification—a possible set of reservoir models is found that may fit the data.
Model-parameter estimation—model parameters are adjusted until the model behavior matches observed data.
Model verification—consistency of the final model is verified by measuring the mismatch between the real system and the model or by comparing with other data.
By use of conventional interpretation methods (i.e., semilog methods such as Horner or Miller-Dyes-Hutchinson, and/or type-curve matching of measured pressure and/or pressure derivative), data including reservoir pressure, an effective average permeability of the formation, skin factor, and wellbore storage can be estimated from the PTT data. In such interpretation, some sort of prior modeling is necessary to constrain the nonlinear parameter estimation because a model with many nonphysical reservoir parameters may match the observed PTT data. This prior knowledge may be available at small scale from logs and cores and at a larger scale from seismic surveys and outcrop analogies. Recently, nonlinear least-squares optimization has been applied to PTT data by use of numerical models with a similarly limited number of parameters—often models that are divided into a small number of regions, within which the reservoir parameters are assumed to be constant.
Cloud Computing: What Upstream Oil and Gas Can Learn From Other Industries
Authors: Perrons Robert K. , Hems Adam 
Published: February 2015

Management
The topic of “the cloud” has attracted significant attention throughout the past few years (Cherry 2009; Sterling and Stark 2009) and, as a result, academics and trade journals have created sever-al competing definitions of “cloud computing” (e.g., Motahari-Nezhad et al. 2009). Underpinning this article is the definition put forward by the US National Institute of Standards and Technology, which describes cloud computing as “a model for enabling ubiquitous, convenient, on-demand network access to a shared pool of configurable computing resources that can be rapidly provisioned and released with minimal management effort or service provider interaction” (Garfinkel 2011, p. 3). Despite the lack of consensus about definitions, however, there is broad agreement on the growing demand for cloud computing. Some estimates suggest that spending on cloud-related technologies and services in the next few years may climb as high as USD 42 billion/year (Buyya et al. 2009).
Roster et al. (2010) identify three of the more commonly cited reasons for migrating functions and capabilities to the cloud:
Cost Reduction. For example, insurance companies are seeking more flexible cost structures, and the cloud allows firms to shift costs to an operating expense rather than a capital outlay, thereby giving them a highly flexible “pay as you go” resource.
Deployment Flexibility. In the media industry, for instance, the type of content that consumers request can suddenly become viral and then immediately fall out of fashion. Demand patterns can therefore swing profoundly from one extreme to the next. A cloud-based infrastructure affords companies in these industries a high degree of flexibility with regard to the amount of computing and data-storage resources that they need at any moment.
Implementation Speed. Doctors in small medical practices usually do not have their own information technology (IT) departments, and cloud computing therefore holds appeal for such enterprises because the technical support bundled into cloud service packages provides the most value for these small businesses in the shortest possible time.
Despite the compelling case for moving toward the cloud, however, the absorption of these technologies and services has been uneven. Some industries—most notably, the financial services and telecommunications sectors—have been relatively quick adopters, while others have approached the cloud more cautiously and slowly.
Optimization Delivers ERD Performance Boost - Sakhalin Island
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 150959, ’Successful Optimization Strategies Combine To Deliver Significant Performance Boost at the Edge of the ERD Envelope-Sakhalin Island, Russia,’ by Richard W. James, SPE, Paul Pastusek, SPE, and Gary R. Kuhn, SPE, ExxonMobil; Anton Andreev, Exxon Neftegas; and Jeffrey R. Bailey, SPE, and Lei Wang, SPE, ExxonMobil, prepared for the 2012 IADC/SPE Drilling Conference and Exhibition, San Diego, California, 6-8 March. The paper has not been peer reviewed.
Many performance-enhancement initiatives were used by the operator of the Sakhalin-I project in drilling and completing the extended-reach-drilling (ERD) program at the Odoptu field, Sakhalin Island, Russia. The initial seven-well ERD program was expanded to nine wells, including the world-record Well OP-11. The operator’s redesign philosophy to remove limiters from the drilling process resulted in significant performance improvements in all areas of drilling and completion operations.
Background
The Odoptu field is one of three fields developed by Exxon Neftegas off the coast of Sakhalin Island, Russia, as part of the Sakhalin-I Project (Fig. 1). The climate is subarctic, with temperatures lower than freezing more than half of the year, and temperatures can drop below −40°C. The field is at the northeastern edge of the Eurasian tectonic plate and is subject to significant earthquake activity, the most recent of which was rated 7.6 on the Richter scale in 1995.
Drilling began in the Chayvo field in 2003, following mobilization of the Yastreb rig to the Chayvo onshore well-site. After drilling one cuttings-injection well and 20 ERD wells, the Yastreb rig was upgraded and moved to the Odoptu North wellsite in late 2008. Drilling commenced from the Chayvo offshore well-site with the installation of the Orlan platform in 2005, where an additional cuttings-injection well and 19 ERD wells were drilled.
During the move from Chayvo to Odoptu, significant upgrades were made to the rig on the basis of lessons learned at Chayvo and to accommodate the higher torque anticipated at Odoptu. The new topdrive could deliver 91,000 lbf-ft of torque at 130 rev/min. A larger mast was required to accommodate the new top-drive, and an additional generator was installed. The drillstring was upgraded to provide significantly higher torque capacity. In addition, the handling capacity of the cuttings-injection unit was increased.
Drilling began at Odoptu in April 2009 (with the cuttings-injection well) and ended in February 2011 (with completion of Well OP-2). Although seven ERD wells were planned at Odoptu initially, the program was expanded to nine wells as a result of drilling successes and favorable production performance. The wells included Well OP-11 with 12 345-m measured depth (MD) and 11 479-m horizontal reach. The Yastreb rig has drilled more than 300 000 m of hole. Following the Odoptu program, the Yastreb rig was moved back to the Chayvo onshore well-site to drill additional ERD wells.
Floating 2-MW Turbine Prototype Tests Feasibility of Harnessing Offshore Wind
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 23492, ’Implementation of a 2-MW Floating Wind Turbine Prototype Offshore Portugal,’ by Christian A. Cermelli, Marine Innovation & Technology, and Dominique G. Roddier and Alla Weinstein, Principle Power, prepared for the 2012 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed.
A 2-MW floating offshore wind system prototype was implemented off the coast of Portugal. The project was designed to prove the technical and economic feasibility
of floating offshore wind turbines in southern Europe. It is based on the WindFloat concept, a three-column semisubmersible-platform design with water-entrapment plates. Such technology enables deployment of multimegawatt wind-turbine generators at great distances from shore, in any water depth. Synergies with offshore oil and gas platforms have been exploited; however, deployment in an area with no previous offshore oil and gas activities led to unique challenges.
Project Design Bases
The project design bases were driven by the following principle: The floating wind turbine should be large enough to provide meaningful testing of fabrication, installation, and operation capabilities. Some of the main project design bases were
A location in 49-m-deep water, 6 km offshore Aguçadoura, a small town located north of Porto on the west coast of Portugal
A wind-turbine size from 2 to 2.3 MW
A connection to the country’s main power grid
Although no specific targets were set for local content, the drive to maximize work performed locally was also seen as a critical success factor for the project.
Previous testing conducted during earlier feasibility studies was performed at a 1/67 scale in a model-testing facility. Intermediate-scale testing (between in-door controlled-environment testing in a wave tank and full-scale prototype) was not seen as a necessary step.
Commercial development of floating wind farms will likely be based on the largest available wind turbines. Currently, 3- to 6-MW machines are available for the offshore market; however, because of budgetary limitations and limited experience with wind turbines of such size, the more common and lower-capacity 2- to 2.3-MW turbines were considered optimal for this project.
A testing site 6 km off the west coast of Portugal was selected because of the presence of a subsea electrical cable with sufficient capacity to transport power from the WindFloat prototype to shore.
The target design life for the plat-form is 5 years, but planned operation should not exceed 2 years.
Smart' Buoy Could Turn Waves into Platform and Subsea Power
Authors: Watson Paul 
Published: February 2015

Technology Update
The use of moored, oceangoing “smart” buoys that can harvest energy from waves could be an efficient and economic means of supplying electric power for various offshore oil and gas operations, including well trees, monitoring systems, and autonomous underwater vehicles (AUVs). Potentially, such technology could reduce, or in some cases eliminate, the use of diesel-powered generators on offshore facilities.
The PowerBuoy (Fig. 1), developed by Ocean Power Technologies (OPT), is new to the oil industry but has been used for a number of years in the defense and utility sectors. The autonomous buoy system consists of a surface float, a spar containing a power takeoff (PTO), a battery system, and a heave plate that constrains the spar’s motions. The system is capable of delivering energy from a few kilowatts to several hundred kilowatts, with future evolution planned to deliver even more power.
The process begins with the rising and falling of waves, and the resultant mechanical stroking is converted by a specially designed PTO to drive an electric generator. This power is transmitted to external equipment by means of an underwater power cable or directly to payloads integrated into the structure itself. Continuous power is then available with the option of larger, timed power bursts.
Advanced internal control systems continuously monitor the various subsystems and the surrounding environment and optimize performance of those systems with data transmitted to shore in real time, providing health and status updates on itself and its attached payloads. With this information, the operator gains a high level of control. Depending on the model of the buoy, the system is designed to need no maintenance for up to 3 years, providing potential savings in operating and life cycle expenses compared with existing power generation alternatives.
Advanced control algorithms have been developed that actively assess oncoming waves to tune the internal PTO dynamically to ensure that it extracts maximum power. In the event of especially large oncoming waves, the buoy will automatically protect itself by locking the float and PTO subsystems and continuing to supply electric power to its payloads by means of the embedded energy storage system (i.e., batteries). The power management system of the buoy manages the state of charge of the battery to ensure efficient overall system operation and to preserve battery life.
Carbon Dioxide May Offer An Unconventional EOR Option
Authors: Rassenfoss Stephen 
Published: February 2015

As the daily oil output of the Bakken and Eagle Ford formations rose toward 1 million B/D, researchers were seeking a way to push the ultimate recoveries in these formations, where producing 6% of the oil in the ground is now considered good.
One line of attack on the problem is using carbon dioxide (CO2) to get more oil from tight formations where rapid production declines are the norm.
In laboratories at the Energy and Environmental Research Center (EERC) at the University of North Dakota and at Texas A&M University, experiments have shown that carbon dioxide circulated around a small sample of source rock can remove a significant amount of oil. Now, the scientists are trying to understand how it works and if those lab results can be applied in the real world.
“It is incredible what CO2 can do,” said John Harju, associate director for research at the EERC, while describing the center’s research program at the annual CO2 Flooding Conference in Midland, Texas.
“The really big prize is (overcoming) the innately low recovery rate in these shale plays,” said David Schechter, an associate professor of petroleum engineering at Texas A&M University who is turning his expertise in conventional enhanced oil recovery to unconventional reservoirs.
While laboratory results normally show much higher recovery than field results, even a 1% improvement of recoveries in the Bakken formation could yield more than 1 billion bbl of oil, according to an EERC paper.
Previous SPE papers, based on reservoir simulation work at Montana Tech of the University of Montana and the Colorado School of Mines, concluded that significant increases in ultimate oil recovery might be possible using CO2 injections.
One of the biggest backers of the work in North Dakota has been Harold Hamm, the chief executive officer at Continental Resources, which pioneered unconventional liquids development and is the biggest acreage holder in the Bakken, Harju said.
On the basis of early tests using CO2 and similar positive results from using chemical surfactants, Texas A&M is working to recruit support from oil companies for a joint industry project called the Enhanced Oil Recovery in Unconventional Reservoirs Joint Industry Project.
Both the EERC and Texas A&M have tested samples ranging in size from Chiclets—square bits of reservoir rock about the size of the popular chewing gum—to small core samples about the size of a disposable lighter. The tests produced significant amounts of oil from samples exposed to CO2 flowing through a test chamber simulating reservoir conditions.