bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Update: New Perforating Gun System Increases Safety and Efficiency
Authors: Salt Warren , Galka Ned , Segura John 
Published: January 2017

Technology Update
Achieving greater efficiency in perforation systems can help lower operating costs, particularly when completing long horizontal wellbores in unconventional plays.
The DynaStage perforating system, developed by DynaEnergetics, incorporates new technology in the addressable firing system and an improved mechanical design that eliminates potential human error. The system can operate more efficiently than traditional systems and, with its additional safety features, allow other wellsite operations to run in parallel with the perforation process.
As a result, the system can achieve improvements in perforation quality and performance reliability, with fewer misruns, while operating efficiently enough to lower total completion costs. The DynaStage system has successfully completed field trials in multiple basins and been commercialized.
The system targets two areas to improve operational efficiency and reduce operating cost.
Safety—the system has a simple, intrinsically safe design that eliminates the risk of inadvertent detonation from stray current or voltage. Surface explosive handling and arming can be conducted in less time and in parallel with other operations. The design eliminates the need to hold the gun system at shallow subsurface depth during simultaneous operations. Both factors reduce wait times at the wellsite.
Reliability—the design of the electronic system and simplification of the mechanical field assembly process help to reduce the number of misruns, which increases efficiency and lowers the cost of completions.
Surface Assembly
Perforating operations with explosives place the explosive components and workers in close proximity, especially during the arming process. Traditional resistorized detonators can contribute to an increased risk of injury and destruction when connecting the detonator to the gun string and the wireline truck.
Safety procedures have been developed to address the risks in this process, and the American Petroleum Institute (API) provides guidelines for safe handling of explosives through Recommended Practice 67 (API RP 67). One of the established best practices is to suspend all surface operations while working with the resistorized detonators. The arming and connection of a gun string at the surface can take up to an hour, meaning that no other wellsite operations can be completed during this time.
The DynaStage system removes the risks of this process by providing an addressable and radio frequency (RF)- safe system with immunity to high voltage and current levels. The firing system is built on a low-voltage, digital communication platform that uses the DynaEnergetics detonator technology, proven to successfully communicate and initiate on command during more than 300,000 perforating operations, without a safety incident. This technology enables the verification of all components in the system, including the addressable switch, the RF-safe detonator, and the RF-safe ignitor, during all phases of the operation.
Intelligent-Completion Installations in the Santos Basin Presalt Cluster
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 174725, “Road to Success and Lessons Learned in Intelligent-Completion Installations at the Santos Basin Presalt Cluster,” by E. Schnitzler, D.A. Silva Filho, F.H. Marques, F.K. Delbim, K.L. Vello, L.F. Goncalez, and T.C. Fonseca, Petrobras, prepared for the 2015 SPE Annual Technical Conference and Exhibition, Houston, 28-30 September. The paper has not been peer reviewed.
This paper presents information regarding the installation of intelligent-well completions (IWCs) in the Lula and SapinhoÁ fields of the Santos basin presalt cluster (SBPSC). The technology is intended to improve reservoir-management capability by using remotely operated flow-control valves and real-time pressure and temperature monitoring for each perforated interval, corresponding to different reservoir zones. The benefits are obtained at the expense of additional challenges for well engineering because well-completion design becomes more complex and overall associated risks increase.
Introduction
The area known as the presalt cluster in the Santos basin is located in ultradeep waters, between 1900 and 2400 m, approximately 290 km from Rio de Janeiro in southeast Brazil. Fig. 1 shows the main blocks of the presalt cluster currently in the appraisal-plan or production-development phases.
The first areas selected for production development were Tupi (BM-S-11 Block) and GuarÁ (BM-S-9 block), which now are known as the Lula and SapinhoÁ fields. Initially, extended well tests were performed in these areas to gather information and test some of the technologies that would be applied on further developments. Later, a production pilot project was initiated in Lula field by the deployment of a production system with a total of nine wells (six producers and three injectors). Since then, new production systems are being deployed continually in the Lula and SapinhoÁ fields.
Since the SBPSC initial phases, IWC was considered one of the more appropriate designs for production-development projects in the field. This technology is expected not only to improve reservoir management but also to provide better capabilities to deal with reservoir uncertainties, which is imperative in carbonate reservoirs.
Intelligent-Completion Systems
Internal risk-analysis assessments before the first production-development project supported the decision to use a two-zone hydraulic system to actuate the inflow-control valves (ICVs). The choice was based on the advice of specialists who considered it to be the simplest and most reliable system in the long term and recognized that it is a field-proven solution. On the other hand, wet trees designed for SBPSC projects contain a multiplex control system, which adds additional integration issues to be addressed during the planning phases.
The HP/HT Completion Landscape
Authors: Carpenter Chris 
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 170919, “The HP/HT Completion Landscape—Yesterday, Today, and Tomorrow,” by Douglas J. Lehr and Scott D. Collins, Baker Hughes, prepared for the 2014 SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. The paper has not been peer reviewed.
The methods used for high-pressure/ high-temperature (HP/HT) tool development are evolving, and development cycles are lengthening, particularly for ultra-HP/HT applications (those involving pressures greater than 15,000 psi or temperatures greater than 350°F) in which materials screening and stability assessments are required. What can the industry anticipate for future HP/HT wells in terms of architecture, product development, and regulatory challenges? This paper identifies current development paradigms and discusses the future challenges in well planning, product development, and regulation.
HP/HT Completion Technology Challenges
The technological challenges associated with the completion of wells at and above HP/HT conditions are diverse and continue to increase. Previous investigations into HP/HT projects identified technology gaps related to packers, bridge plugs, liner hangers, subsurface safety valves (SSSVs), tubing-to-packer seals, and related products. (Please see the complete paper for a comprehensive list of challenges faced in HP/HT environments, as well as a discussion of the historical perspective in HP/HT well development.)
In addition to the general challenge of materials design and testing for HP/HT environments, several specific component-based challenges also exist.
Packers. Packers and bridge plugs have been developed for service conditions as challenging as 500°F and 25,000 psi, but the primary difficulty in the development process today is the availability of materials, both metallic and nonmetallic, which are suitable for very high levels of stress and strain and which possess the desired corrosion resistance to achieve longevity requirements.
SSSVs. SSSVs contain many dynamic seals which must maintain their integrity and operating characteristics over the life of the completion. Also, the operator must have the capability to extend the life of a malfunctioning safety valve through the use of “insert valves.” These are smaller-diameter wireline-conveyed valves that can be run and inserted into the bore of the tubing-mounted safety valve so that production can continue under fail-safe conditions.
Streamline-Based History Matching for Multicomponent Compositional Systems
Authors: Carpenter Chris 
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 174750, “Streamline-Based History Matching of Arrival Times and Bottomhole-Pressure Data for Multicomponent Compositional Systems,” by Shusei Tanaka, Dongjae Kam, Akhil Datta-Gupta, and Michael J. King, Texas A&M University, prepared for the 2015 SPE Annual Technical Conference and Exhibition, Houston, 28–30 September. The paper has not been peer reviewed.
Streamline-based history-matching techniques have provided significant capabilities in integrating field-scale water-cut and tracer data into high-resolution geologic models. However, application of the streamline-based approach for simultaneous integration of water cut and bottomhole pressure (BHP) has been rather limited. In this paper, the authors introduce a novel semianalytic approach to compute the sensitivity of the BHP data with respect to gridblock properties.
Introduction
The streamline-based method has many advantages in terms of computational efficiency and applicability. The main advantage of the streamline-based method is that it is able to calculate parameter sensitivity with a single streamline simulation or post-processing of the grid-based finite-difference simulation results. The calculated sensitivity is comparable with the sensitivities computed from numerical perturbation or with adjoint-based sensitivities. It is possible to calculate the parameter sensitivity from a commercial finite-difference simulator by use of streamlines traced using the flux field. This allows accounting for detailed physics by means of finite-difference simulation while taking advantage of the power of the streamlines for sensitivity computations.
Streamline and Parameter Sensitivity
Streamline-based history matching starts with the tracing of streamlines from a given set of static and dynamic conditions. This process is outlined in detail in the complete paper.
Amplitude, Travel-Time, and Generalized Travel-Time Inversion (GTTI) Methods
The approach to minimizing the objective function through all the observed points and simulation results is defined as amplitude inversion. The travel-time inversion, instead, attempts to match single reference times such as water-breakthrough point or peak tracer response. The amplitude matching is general in terms of reduction of the objective function, because while the travel-time inversion reduces the objective function at only a single point, the amplitude matching can cover all the data points. However, the travel-time-based approach is often used because amplitude inversion is a highly nonlinear problem and presents difficulties in computational cost and in reducing the objective function when there is a large amount of wells and data points.
Improving People’s Lives: Hope Is Not a Strategy … But Without Hope, There Is No Strategy
Authors: Meehan Nathan 
Published: January 2017

President's column
A great benefit of being the SPE president is the chance to interact with students and young professionals around the world. Many are anxious about the future, but not panicked. I have been asked if this is the worst time ever in the oil business, a question that made me smile.
For some reason, it is natural to try and “scale” a current calamity with past ones. For example, financial recessions are compared with the Great Depression of the 1930s during which the worldwide gross domestic product (GDP) dropped 15% in 3 years. In comparison, the recession of 2008– 2009 saw a 1% drop in worldwide GDP but certainly felt huge. WTI crude oil prices dropped from USD 145.31/bbl on 3 July 2008 to USD 30.28/bbl in less than 5 months. The US rig count followed suit, dropping from 1,987 in August 2008 to 895 by mid-2009. It certainly was not good, but it was relatively short-lived.
Fig. 1 compares US rotary rig activity during the four most recent significant downturns. Leo Tolstoy’s quote about families may be paraphrased to apply to downturns: “Each oil price downturn is unhappy in its own way,” and each downturn and recovery had different causes. In Fig. 1, I have started with the peak US rig activity immediately prior to the beginning of the downturn and normalized subsequent weekly activity to this peak. Each prior downturn recovered to about 80% of peak activity within approximately 2 years after dropping from 45% to 55% of peak activity.
We are currently at less than 25% of the prior peak activity level and at an all-time low for the Baker Hughes reported US rig count dating to 1944. Compare this with the 1980s. In late 1981, rig activity peaked at 4,530 rigs and in the subsequent “ice age,” the rig count dropped to 663, less than 15% of the peak. While this was a steeper drop from the peak level, current rig activity is now approximately 70% of that ice age bottom, and future drops are certainly possible. Current rig activity is lower than what the US has seen in a very long time.
Is the Current US Rig Count the Lowest Ever?
I have been looking at historical rig activity measures. The Baker Hughes rig count data from 1944 include only rotary rigs. Before the 1950s, cable tool rigs accounted for a significant portion of drilling activity. Cable tool drilling dates to 1806 with horse-powered rigs. These were replaced in the 1830s by steam engines to provide rig power, and in 1860 when J.C. Rathbone used a steam-powered cable tool rig to drill a 100-B/D producer in West Virginia, cable tool activity took off. During the US Civil War, many hundreds of cable tool rigs were drilling, primarily in West Virginia, California, and Pennsylvania. If we include cable tool rigs, total US rig activity has exceeded 500 rigs since Abraham Lincoln was the US president, making the rig activity of 464 as of 24 March this year a truly historic low.
Technology Update: Biocide Treatment Program Reduces Premature Coiled Tubing Failures
Authors: Edillon Lemuel , Henderson Matthew , Leong Stan 
Published: January 2017

Technology Update
Premature coiled tubing (CT) failures have occurred in the United States, in areas such as the Eagle Ford and Haynesville formations, and the Permian Basin. In Canada, these failures once were not considered as prevalent. However, a presentation at the 2015 SPE/ICoTA conference in The Woodlands, Texas, changed that perception. A paper presented there detailed how a major Canadian CT service provider experienced a series of CT string failures while performing bridge plug millout operations in the Montney formation in northeastern British Columbia (Edillon et al., 2015).
With each trip in or out of the wellbore, CT strings incur fatigue that can be estimated using simulation software based on the CT outside diameter (OD), material grade, and operating conditions. CT strings can fail for a variety of reasons, including external mechanical damage, corrosion, and excessive diametrical growth. Premature failure results not only in operational delays and the associated costs, but critical safety risks for onsite personnel.
For these reasons, a study was undertaken to determine the root cause of the CT string failures in the Montney. The results showed that microbial influenced corrosion (MIC) was a contributing factor. This led the CT service provider to instigate laboratory and field studies to create a biocide treatment program. The program has successfully mitigated further CT string failures in the Montney and has now been applied to CT programs in the Eagle Ford formation.
CT String Analysis
Seven failures of 60.3-mm (2.375-in.) CT strings supplied by multiple manufacturers were experienced over 2½ months. The strings failed in the range of 18% to 49% fatigue—well below their predicted 80% fatigue life. Preliminary analysis of the failure points revealed pinholes and internal corrosion in the base material and at the bias weld. The filler material used in bias welds has different mechanical properties than the base pipe material, making it weaker and more fatigue-prone.
To determine the failure mechanism, CT strings from four of the seven units were further analyzed by the manufacturers. In all four cases, internal corrosion pitting was observed. Comprehensive analysis on one string, including scanning electron microscopy, energy-dispersive X-ray spectroscopy, and metallography, was performed by the manufacturer and the University of Calgary. The analysis revealed that failure occurred at the bias weld and indicated microcorrosion pitting and transverse cracking in the weld filler material (Fig. 1). The corrosion morphology (rounded shape with light green corrosion debris) and the presence of sulfur in the corrosion product provided indirect evidence of MIC.
Stuck-Pipe Prediction With Automated Real-Time Modeling and Data Analysis
Authors: Carpenter Chris 
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 178888, “Stuck-Pipe Prediction Using Automated Real-Time Modeling and Data Analysis,” by Kent Salminen, SPE, Curtis Cheatham, SPE, Mark Smith, SPE, and Khaydar Valiulin, SPE, Weatherford, prepared for the 2016 SPE/IADC Drilling Conference and Exhibition, Fort Worth, Texas, USA, 1–3 March. The paper has not been peer reviewed.
A real-time method is presented to predict impending stuck pipe with sufficient warning to prevent it. The new method uses automated analysis of real-time modeling coupled with real-time- data analysis. It can be applied to all well types for any well operation. The new method combines two types of analysis: (1) deviation of real-time data from real-time model predictions by use of hydraulics and torque-and-drag software, and (2) trend analysis of real-time data.
Data Types and Frequency
The approach taken was to first study real-time data sets from wells in which stuck-pipe incidents occurred and determine the root cause of each. The majority of these wells were drilled between 2009 and 2013 in the Eagle Ford shale. Specific patterns in the data were then identified as potential leading indicators of stuck pipe.
One of the first issues identified was that the type, frequency, and quality of data available are not consistent from well to well. To ensure that the alerting system was configured to work on different well types with a high degree of functionality, the decision was made that it would be designed to monitor a well and provide alerts even if only “critical” data streams are available. These critical streams would meet the following criteria:
Available on most rigs capable of capturing real-time data
Be useful in determining information about the drillstring, drilling fluid, and the wellbore itself
Fit within a logical progression that can indicate impending stuck pipe
Production Performance in the In-Fill Development of Unconventional Resources
Authors: Carpenter Chris 
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 175963, “Production Performance in the In-Fill Development of Unconventional Resources,” by Bilu V. Cherian, Sanjel; Matthew McCleary, Samuel Fluckiger, Nathan Nieswiadomy, Brent Bundy, and Sarah Edwards, SPE, SM Energy; and Rafif Rifia, Kristina Kublik, Santhosh Narasimhan, James Gray, Olubiyi Olaoye, and Hamza Shaikh, Sanjel, prepared for the 2015 SPE/CSUR Unconventional Resources Conference, Calgary, 20–22 October. The paper has not been peer reviewed.
Data now show that the behavior of unconventional wells to in-fill drilling varies significantly across basins. A key influence may be changes in pore pressure and saturation (saturation history). This paper presents results from the analysis of the effect of in-fill drilling on parent-well performance, and describes a simplistic approach to understanding the effect of the quest for operational efficiencies and economic cycles on development strategies.
Methodology
This study focuses on two unconventional plays, the Eagle Ford and the Bakken. The objective was to model the well performance of the parent wells with the aim of matching and predicting in-fill-well performance. Because the two assets are at two significantly different portions of the development cycle (Eagle Ford is very early in its cycle), the Bakken data set has the luxury of modeling and matching the performance of the parent and in-fill, whereas the Eagle Ford portion of this study focuses on forward modeling and optimizing in-fillwell completions.
The methodologies used in this study (parent-well modeling, petrophysical models, geomechanics, fracture modeling, production modeling, and in-fillwell/ depletion modeling) are discussed in detail in the complete paper.
Bakken System Parent-Well Modeling
Petrophysics. The Middle Bakken member was divided into three main facies. Petrophysical evaluation indicates that average porosity and average water saturation were 8 and 50%, respectively, for the Middle Bakken. Average Klinkenberg permeability for the entire Middle Bakken is approximately 0.02 md. Mercury-injection capillary pressure curves indicate that irreducible water saturation is between 30 and 40% for rock with porosity between 1 and 7%. Residual oil is between 30 and 40%. Accordingly, the moveable fluid is low (20–40%), and hydraulic fracturing was recommended to stimulate more production.
The Three Forks formation was divided into five facies. Petrophysical evaluation suggests that the upper part of the Three Forks, Facies TF 23, has oil potential. Most facies are strongly affected by calcite and dolomite diagenesis, which allows alternating porosity development in some cases. In this area, the Middle and Lower Three Forks have higher water saturation, with very-low-permeability streaks (less than 0.007 md).