bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Approach to Deepwater-Drilling-Data Analysis Enhances Real-Time Capabilities
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 146624, ’A New Approach to Deepwater Drilling Data Analysis Offers Enhanced Real Time Capabilities in a Post Macondo World,’ by John F. Greve, SPE, Chevron Deepwater Gulf of Mexico Business Unit, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed.
Deepwater drilling activity in the Gulf of Mexico is no longer a given in the aftermath of the BP Macondo blowout. The new and ever-evolving process to apply for drilling permits and operate now greatly depends on thorough real-time monitoring of pertinent surface and downhole data. A new method for loading and analyzing live time and depth data showed merit during 2010 trials on two deepwater wells, one offshore eastern Canada and the other offshore west of the Shetland Islands. Rapid data access and standardized visualization of high-resolution time, depth, and survey data are vital to ensure that the occasional well-control event does not become today’s worldwide news headline.
Background—Real-Time Data Collection
The Wellbore Information Transfer Standard Markup Language (WITSML) well-data exchange protocol introduced in the mid-1990s continues to gain popularity as a standardized means to deliver drilling and logging data to the client operator. An increasing number of software programs are offering WITSML links to load depth-based data into programs for petrophysical analysis, pore-pressure estimation, and 3D visualization of well logs vs. seismic data. For roughly a decade, large service companies have offered Web-based viewing of drilling-gauge displays and real-time depth-based data. Even though Internet access to WITSML data has been available to client operators, little benefit has been derived from the time-based data because of inherent limitations of depth-focused Web-based viewers. A new vendor-neutral WITSML-based data viewer capable of easily connecting to multiple WITSML vendors combines real-time synchronous depth and time viewing of drilling, logging-while-drilling (LWD), and mud-logging data in a variety of graphical displays.
Historical Perspective on Collection of Time-Based Drilling Data
For many decades, time-based drilling data have been recorded with mechanical devices. Special 24-hour multiscale paper forms were loaded on a cylindrical drum every day. Because the chart was under a protective lid and sometimes covered by dirt and mud, it was considered more of a midnight chart-replacement chore for a roughneck than a useful tool. The charts rarely made it to the operator’s office and were often lost or thrown out.
Hybrid System Brings Flexibility of CT to Long, Extended-Reach Wells
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 142769, ’New Hybrid System Brings the Flexibility of Coiled Tubing to Long, Extended-Reach Wells,’ by F. McNeil, SPE, S.D. Lindsay, SPE, R. Lyons, and R.P. Gracey, Halliburton, prepared for the 2011 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 5-6 April. The paper has not been peer reviewed.
The number of long extended-reach wells being drilled in the oil and gas industry continues to increase. These wells present complex challenges in completion and intervention procedures because operators demand the same level of performance achieved on shallower wells while providing a cost-effective and safe solution. To reach deep target depths with coiled tubing (CT), smaller coil must be used because of reel capacity, which limits pumping rates because of pressure and velocity limitations. As an alternative, jointed pipe can be used; however, using jointed pipe reduces the overall efficiency of the process because continuous pumping cannot be achieved. A new hybrid system uses both CT and jointed pipe in a single work string. The system incorporates a unique flapper safety valve that enables seamless functioning of the string in a live well. The hybrid system enables larger CT and jointed pipe to be deployed, which results in higher pumping rates and greater depths.
Large CT
Reel Capacity. A major hurdle when considering large lengths of CT is reel capacity. For example, the maximum length of coil that can be stored on a standard reel [assuming 144-in. reel outer diameter (OD)] is as follows:
1¾-in.-OD CT: 19,670 ft
2-in.-OD CT: 14,795 ft
2⅜-in.-OD CT: 10,151 ft
Lockup. Another important consideration in the design of any CT job in a highly deviated deep-reach well is lockup. Lockup occurs when CT forms a helix inside the casing and high wall-contact forces prevent any additional forward movement. While this effect will occur in all CT, smaller CT is more susceptible to complete lockup at shallower depths than larger CT. Therefore, larger CT is more likely to reach target depths.
Wellbore Cleanouts. Accumulation of sand and solids in wellbores significantly impairs oil and gas production; an influx of sand can impair or stop the flow of oil from a reservoir. This is commonly dealt with by CT intervention; in fact, nearly half of all CT operations involve well cleanouts. Conventional CT units are limited to small-OD coil when performing remedial operations on deep wells because of limitations in reel size, as well as local laws regarding width, height, length, and weight restrictions.
Technology Focus: Well Construction (May 2012)
Authors: Carpenter Bob 
Published: February 2015

Technology Focus
The number and economic contribution of unconventional (tight gas/shale and steamflood) wells continued to increase rapidly in 2011, as did the participation of major operators. That increased industry focus was evident again in the distribution of papers. Also, there were more papers relating advances in plug-and-abandonment, Arctic, high-pressure/high-temperature (HP/HT), and carbon-capture technologies.
Manny Gonzalez, Chevron Energy Technology Company’s Alliance Manager, noted that the huge interest in shale-formation completions calls for efficient controlled fracturing technology to ensure economic viability and an environmentally responsible well completion. SPE 152185 outlines a direct comparison of openhole vs. cased-hole fracturing in a tight gas reservoir. The presented results are surprising, and the effects on incremental production, fracture height, and fracture half-length are significant—a good read.
Operators have been plugging nonproductive and storm-damaged wells at an increasing rate, and effective abandonment operations can prove costly and challenging. SPE 148640 relates a novel and well-detailed approach to a more efficient plug-and-abandon process and to the process of confirming plug integrity across an uncemented section of annulus. Check it out.
Industry emphasis on long-term well reliability has continued to increase, especially for steamflood projects. SPE 150022 details a very thorough look into the many design and operational factors that affect well reliability in a high-temperature (285°C) steamflood. While only briefly mentioned, the authors undertook controlling the rate of temperature change, and thus controlling temperature disparity (∆T) between casing, cement sheath, and formation during injection cycles. Controlling injection events can have a strong effect on the reliability of a steamflood well or even a deepwater or HP/HT well. This is the first field effort at controlling such events that I recall.
Recommended additional reading at OnePetro: www.onepetro.org.
CMTC 152259 The Cement-Industry Roadmap To Reduce Carbon Emissions by L. Barcelo, Lafarge, et al.
SPE 148639 An Integrated Fluids Approach To Enhance Zonal Isolation in Deep Khuff Gas Producers and Injectors Offshore Abu Dhabi by Mohammed A. Mehtar, SPE, Abu Dhabi Marine Operating Company, et al.
IPTC 14913 A Paradigm Shift in Testing and Completion of Deep HP/HT Exploration Wells—Polished-Bore Receptacle (PBR) Improves Results and Operational Flexibility by Anwar Ibrahim, Kuwait Oil Company, et al.
Extreme-Environment Cementing in the Schoonebeek Heavy-Oil Field
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 150022, ’Contemporary Approach Coupled With Traditional Techniques Tackles Extreme Wellbore Environment in Schoonebeek Heavy-Oil Field,’ by Andrew Foster, Auke Pollema, Ian Petitt, SPE, and James Heathman, SPE, Shell, and Carl Johnson, SPE, and Rudy Schlepers, Schlumberger, prepared for the 2011 SPE Heavy Oil Conference and Exhibition, Kuwait City, Kuwait, 12-14 December. The paper has not been peer reviewed.
The Schoonebeek heavy-oil field was first developed by Nederlandse Aardolie Maatschappij B.V. in the late 1940s. Because of economics, it was abandoned in 1996. In 2008, the Schoonebeek Redevelopment Project, using a gravity-assisted-steamflood (GASF) design concept, was initiated with 73 wells (44 producers, 25 injectors, and four observation wells). A key design requirement was long-term integrity of the cement sheath over an expected 25- to 30-year field life span. Complicating this requirement was the need for systems to place lightweight cement because lost-circulation issues were expected in both hole sections, particularly in the mechanically weak Bentheim sandstone.
Introduction
The Schoonebeek field was discovered in 1943 and was on production until 1996. During this period, 597 vertical and deviated wells were drilled. In 1995, two horizontal wells were drilled to test borehole stability while drilling horizontals and test sand production during the production phase. Core data in numerous vertical wells show that the reservoir is coarsening upward. The lower part of the reservoir has a lower permeability than the upper part of the reservoir. One-fourth of the original oil volume was produced over the approximately 50-year period (more than 250 million bbl). Approximately 120 million bbl is expected to be produced by use of the GASF technique. Planned plateau production is 3000 m3/d, with a steam-injection plateau of 8000 to 10 000 m3/d.
Cementing thermal wells, particularly cyclic-steam-injection wells, is one of the most crucial and challenging cementing operations. Maintaining well integrity and zonal isolation over time is critical to the economic success of a steam project. The fundamental purpose of primary-cementing operations is the provision of effective zonal isolation during the life of the well. As wells become more challenging, more demands are placed on the cement-slurry design, operational practices, and in-situ properties of the well annular sealant. Uniform competent cement sheaths can minimize buckling, collapse, parting, or elongation caused by thermal stress.
Innovation: Funding SPE Programs and Services
Authors: Imomoh Egbert 
Published: February 2015

President's column
In the next two months, I am going to deviate from the theme of my previous columns on innovation. As indicated above, this month I will share with you how SPE funds its programs and services and next month I will write about the work on strategy that your board has been working on.
I am happy to report that our membership continues to grow. Total SPE membership (professional and student) exceeded 110,000 at the end of 2012. These members continually look to SPE for good programs and services, and our mission to disseminate technical information to all of them and to do so quickly, affordably, and in new ways, is increasingly challenged. SPE accomplishes this primarily through meetings, lectures, training courses, and publications. So, how does SPE fund all of these things?
All of SPE’s major business segments (meetings, publications, membership, re-tail sales, SPE.org) contribute to the overall success of SPE, but as Fig. 1 illustrates, meetings are SPE’s largest source of revenue. Although SPE now conducts around 140 events worldwide each year, most of the revenues from meetings come from the financial success of a small number of conferences with large exhibitions, like the Offshore Technology Conference and Offshore Europe. Most other events are budgeted to break even or generate a small surplus.
Your board recently considered and approved SPE’s budget for Fiscal Year 2014 (1 April 2013 through 31 March 2014). It has total operating revenues of USD 92.4 mil-lion and expenses of USD 84.4 million, resulting in a net income of USD 8 million. Here is the important thing to remember when you are considering these numbers. Unlike commercial organizations, our income goes back into benefits for our members. This helps us keep dues, meetings registrations, and publications prices reasonable, and helps us support programs that produce little or no revenue on their own, like scholarships, the very popular Distinguished Lecturer visits, and our peer-reviewed journals.
Downhole Gauges Meet Challenges of Operating Beside ESPs in HT Reservoir
Authors: Kettle Bob , Scott Michael 
Published: February 2015

Technology Update
Talisman Energy needed to enhance its continuous downhole monitoring capability at the Gyda field offshore Norway with a system that could perform in high-temperature (HT) conditions and operate beside electric submersible pumps (ESPs) in two oil production wells.
Situated in the southern Norwegian Sea 270 km from Stavanger, Gyda is a mature field in which production peaked in 1995. To address the increasing water production and decreasing reservoir pressure, the company installed ESPs in the completion of new wells A-19A and A-26 in 2011. Estimated field production for 2011 was 8,000 BOPD, according to the Norwegian Petroleum Directorate. The field’s production license was recently extended to 2028.
Challenges for New Monitoring System
The Gyda field has an extensive permanent downhole monitoring network that tracks information on individual well conditions, such as temperature and pressure. Through sensors, gauges, and other downhole operating equipment, Talisman can monitor and, if necessary, maintain pressure; control each well; and optimize field production. However, adding monitoring systems to the A-19A and A-26 wells presented special challenges.
The systems, which would need to monitor well zone conditions and the ESPs to ensure their function at the optimum points of their pump curves, would face reservoir temperatures as high as 160°C (and pressures as high as 300 bar). The HT environment can put enormous stress on instrumentation and impair its ability to generate reliable data. The standard gauges designed for the ESPs were not qualified to operate at the higher temperature levels found in the Gyda reservoir, thus further justifying the need for enhanced permanent monitoring.
Another challenge was that the new downhole monitoring systems would have to operate effectively next to the ESPs. These pumps require large amounts of power, which is transferred downhole on a three-phase cable. This cable runs alongside the ESP cable and is susceptible to noise disturbance from the pumps’ motors and variable speed drive (VSDs).
The VSDs—at 12 and 24 pulse, for example—can cause total harmonic distortion. This can be induced onto the downhole gauge control lines and interfere with downhole communication and gauge electronics, particularly during an ESP startup when the drive current can be six to eight times the normal operating current.
Decade of Stimulation Experience in the Deepwater Gulf of Mexico
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 159660, ’A Decade of Deepwater Gulf of Mexico Stimulation Experience,’ by Lee N. Morgenthaler, SPE, and Leigh A. Fry, Shell E&P, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-10 October. The paper has not been peer reviewed.
The deepwater Gulf of Mexico is a technically and economically challenging production environment. High rates and ultimate recoveries are required per well to offset high development costs. Stimulation treatments maintain wells at peak production rates and accelerate reserves recovery. In these complex layered reservoirs, stimulation is necessary to ensure recovery volume. The primary objective of stimulation is to restore impaired well/reservoir connectivity. Successfully identifying the cause and location of impairment is required. Looking back over a decade of experience in this challenging environment yields useful insights as the industry moves into new deepwater provinces.
Introduction
Shell’s deepwater development began in 1991 with the Tahoe subsea prospect tied back to the Main Pass 252 platform. Development continued with the Auger, Mars, Ram Powell, Ursa, and Brutus tension-leg platforms (TLPs) and many subsea fields that tie back to them (Fig. 1). Most of the reservoirs producing to these structures are geologically young turbidite sands that require sand control. Initially, all of the fields were geopressured significantly above hydrostatic and were significantly undersaturated. The soft compacting sands and aquifer support often provide sufficient energy to achieve adequate recovery by depletion.
The hydraulic fractures created in the frac-pack process provided lower skin values with minimal use of acid. The horizontal openhole gravel packs used acid-soluble bridging agents to stabilize the wellbore during gravel packing. The bridging agents were then removed with acid washing. Because most of these sand-control completions were cased-hole gravel packs or cased-hole frac packs, most of this paper refers primarily to the experience with those completion types.
As the fields matured, there were more subsea-tieback developments. Stimulation campaigns generally focused on the direct-vertical-access (DVA), or dry-tree, wells of the TLPs. However, stimulation of subsea wells has been highly profitable, and technology has been developed to reduce the subsea-intervention costs to make these interventions more attractive. The complex operations on TLPs introduce challenges when planning and conducting stimulation operations. Logistics coordination and proper management of returning wells to production are critical to realize production gains and to meet environmental-discharge regulations and goals.
Who Dat Project - Deepwater Subsea Production of Light and Heavy Oil
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 23378, ’Subsea Who Dat Project—Producing Light and Heavy Oil in a Deepwater Subsea Development,’ by Gerard J. Simms, SPE, Bruce Cooley, SPE, and Rick Fowler, SPE, LLOG Exploration; Kosta J. Leontaritis, SPE, AsphWax; and Kana Krishnathasan, SPE, Intecsea, prepared for the 2012 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed.
Plans were developed to produce multiple deepwater reservoirs with vastly different fluid properties from a subsea development in 3,100 ft of water in the Gulf of Mexico. Diagnostic and flow-assurance (FA) testing of the different-density oils addressed viscosity including non-Newtonian, wax, asphaltene, and hydrate behavior; downhole and flowline commingling; and fluid-compatibility tests. Provisions for pigging and a chemical-treatment program were added for extra assurance. A larger-sized oil-export line was selected to allow sufficient capacity for blended or heavy oils after restart.
Introduction
The Who Dat field is in the Mississippi Canyon protraction area of the Gulf of Mexico and is being developed with the Opti-Ex semisubmersible floating production system (FPS), which has a capacity of 60,000 BOPD and 150 MMcf/D of gas. The field primarily contains oil and consists of ten stacked amplitude- supported reservoirs in a salt-withdrawal minibasin. Three wells had been drilled at the time this paper was written, penetrating more than 700 ft of net pay in nine distinct reservoirs ranging in depth from 12,000- to 17,000-ft true vertical depth. Both gas and oil reservoirs were found, with varying fluid properties. Significant fluid data were acquired in the openhole program, with more than 60 downhole fluid samples. Twelve full pressure/volume/temperature (PVT) studies and eight diagnostic FA studies were performed to gain an early understanding of the fluid. Later, flowback oil samples were acquired, rechecked, and evaluated further.
Field development includes 12 subsea wells (i.e., wet trees) flowing into three four-slot subsea manifolds. Drill Center A has one manifold, and Drill Center E has two manifolds. Each manifold is connected to the FPS with dual 6-in.-nominal-diameter wet-insulated flowlines and flexible risers having the capacity of roundtrip pigging. These infield flowlines are approximately 3 miles long, and the seafloor geometry results in a downsloping flowpath. The project includes a 10-in. gas-export line and a 14-in. oil-export line, also with flexible risers. Fig. 1 shows the subsea layout.
The key inputs for the FA process are uncontaminated fluid samples and detailed laboratory analysis. In the case of system selection for the Who Dat field, fluid samples were available from three wells and multiple formations. There were uncertainties about key formation-fluid properties resulting from drilling-fluid contamination, including viscosity, foaming, and wax content.