bluuebunny/crossref_metadata_2025 huggingface dataset:
Downhole Mixing Technique Facilitates Pinpoint Fracturing in Eagle Ford Shale
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 153312, ’Downhole Mixing Fracturing Method Using Coiled Tubing Efficiently: Executed in the Eagle Ford Shale,’ by S. Lindsay, SPE, C. Ables, SPE, and D. Flores, Halliburton, prepared for the 2012 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 27-28 March. The paper has not been peer reviewed.

The increased demand for natural gas from shale plays in the United States has forced the industry to be more efficient and develop innovative methods for fracture-stimulation optimization. Pinpoint-fracturing methods represent a divergence from the conventional methods, with minimal optimization needed to help maximize reservoir volume. Multiple-interval completions can be performed efficiently so that all intervals receive the designed proppant volumes, one interval at a time. To accomplish this efficiency, coiled tubing (CT) is used to hydrajet perforate intervals for individual fracturing treatments at predesigned depths. The latest pinpoint-fracturing technique provides maximum engineering flexibility in the execution of these treatments by allowing downhole control of the proppant schedule; this can be used to optimize the stimulated reservoir volume (SRV) on the fly, in real time, and with downhole control. The process also incorporates large-outer-diameter (OD) CT. A recent 25-interval completion in the Eagle Ford shale demonstrated the process.

Introduction

The downhole mixing process (DMP) allows multiple-interval fracturing treatments in horizontal laterals in a single trip. The DMP enables the fracturing treatment to be manipulated in real time. This allows the altering of bottomhole conditions to increase net pressure, resulting in increased complexity and more SRV compared with conventional casing fracturing treatments.

Using this method, multiple treatments can be performed in a time-effective manner with less hydraulic horsepower (HHP) on location. This is a result of the higher rate per interval that is pumped into the formation. On a typical 100-bbl/min treatment with four perforation intervals, each interval receives only at a 25-bbl/min fracturing rate. This, of course, is assuming that all the intervals are of a homogeneous rock type, have the same fracture-initiation and -extension pressures, and are all receiving fluid.

With the DMP, each interval is fractured individually, helping ensure that all fluid enters the desired area of the formation at the desired pumping rate. This results in a reduction in required HHP; for example, only 25 bbl/min must be pumped to achieve the desired 25-bbl/min fracturing rate in that interval. An example of this process is illustrated in Fig. 1.
Technology Focus: Enhanced Oil Recovery (June 2012)
Authors: Bonet-Cunha Luciane
Published: February 2015

Technology Focus

Enhanced-oil-recovery (EOR) operations are what moves EOR processes from the laboratory to the field. They involve a series of activities, from a detailed planning stage to efficient application, consistent monitoring, and results analysis. When reviewing results from field pilots or full-field applications, it is noticeable that significant technical hurdles such as facilities, drilling and completion, and production-technology developments need to be overcome in order to deploy and run a successful EOR operation. Technology developments in water management, intelligent-well completions, and downhole innovation are key for EOR operations to achieve the expected increases in reserves.

Over the past year and during the first quarter of 2012, SPE was host to several events focusing on EOR operations, and more than 400 papers were presented. Several of them explored topics related to enhancements associated with the three key areas mentioned. Emphasis in many papers concerns extending the use of smart-well completion technologies to EOR operations, targeting customization to set out an EOR process and provide more flexibility for the solution to unexpected setbacks during process startup. Also, several publications stress the importance of downhole innovation aiming at oil- and gasfield production maximization by continuous optimization of steam and CO2 downhole injection rates in heavy-oil recovery and CO2-EOR processes, respectively.

Dealing with EOR operations adequately is a great challenge, and a broad and integrated set of competencies is required. Nevertheless, as some of the papers featured in this issue illustrate, success is attainable with the right use of technology and creativity. I hope that you enjoy reading these paper highlights and will search for additional interesting contributions available in the OnePetro online library.

Recommended additional reading at OnePetro: www.onepetro.org.

SPE 150477 SAGD Field Trial for a New Intelligent-Well Completions Strategy To Increase Thermal EOR Recoveries by Joel Shaw, Halliburton, et al.

SPE 154318 The Design and Execution of an Alkaline/Surfactant/Polymer Pilot Test by A. Sharma, Rex Energy, et al.

SPE 154122 Mobility and Conformance Control for CO2 EOR Via Thickeners, Foams, and Gels—A Literature Review of 40 Years of Research and Pilot Tests by R.M. Enick, University of Pittsburgh, et al.

SPE 144893 Seventeen Years of Development of Artificial Lift Technology in ASP Flooding in Daqing Oil Field by Yang Yonghua, China University of Petroleum, et al.
Comparative Analysis of Electromagnetic Heating Methods for Heavy-Oil Recovery
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 150550, ’Comparative Analysis of Electromagnetic Methods for Heavy Oil Recovery,’ by Igor Bogdanov, SPE, Jose Antonio Torres, SPE, and Arjan Kamp, SPE, CHLOE, and Bernard Corre, CSTJF-Total, prepared for the 2011 SPE Heavy Oil Conference and Exhibition, Kuwait City, Kuwait, 12-14 December. The paper has not been peer reviewed.

Thermal methods are well-known for enhancing oil recovery by decreasing reservoir-oil viscosity substantially by raising the temperature. Although it is one of the more popular thermal methods, steam injection is not always applicable successfully in real reservoir conditions because of prohibitive heat losses from injection wells and reservoirs, low reservoir injectivity (especially for bitumen deposits), steam leakage, and other environmental problems. Fortunately, a good alternative to steam injection exists—electromagnetic heating (EMH), which includes a variety of methods.

Introduction

Different physical mechanisms, according to the frequency of the electromagnetic (EM) field, are responsible for the heating. For instance, low-frequency heating (LFH) is based on the Joule effect. Inductive heating (IH) is the process where Foucault (eddy) currents generated within a load also result in Joule heating. Finally, high-frequency heating (HFH) consists of in-situ dielectric heating from rotation with friction of polar molecules in the EM field.

An EM field facility is installed normally in a wellbore; the EM power is converted into heat inside the reservoir, leading to an increase of local temperature. The advantages of EMH methods—avoidance of low-injectivity/-connectivity and injection-pressure-related problems—are complemented by in-situ heat generation and, particularly, water evaporation (e.g., during HFH).

The common physical nature of the phenomena under consideration explains similar features in the EM-field distributions. Consider, for instance, that each method has a nearly singular electric field close to the source, which depends on both the source geometry and the frequency of EM waves. Another common point is that these techniques are efficient only if some critical amount of connate water is present initially in a reservoir. Water’s electric properties make the methods applicable for a wide range of reservoir conditions. LFH differs from the other two methods in that its use is limited by the existence of an effective electrical circuit—in other words, LFH requires continuous conductive paths for electric current between electrodes. This means that the reservoir water must always be liquid around the electrodes. If it is not, the electrical circuit will be disconnected, and no electrical current means no heat. For IH and HFH, this is not true because the EM waves propagate (without absorption) through a dry porous medium. However, as in LFH, no heat is released in the dry medium.
Comments: Offshore Resilience
Authors: Donnelly John
Published: February 2015

Editor's column

Twenty-five years ago next month, the oil and gas industry’s worst offshore disaster took place. The explosion and fire on the Piper Alpha North Sea oil production platform killed 167 men and left only 61 survivors. The anniversary will be commemorated with a 3-day safety conference in Aberdeen and the refurbishment of a memorial sculpture honoring the victims.

The accident ushered in a new safety culture in the oil and gas industry as well as a new regulatory mandate. That sector of the industry recovered and has made steady improvements in safety since. Three years ago, the Macondo Gulf of Mexico accident rocked the industry, and its implications are still being felt. From all appearances at last month’s Offshore Technology Conference in Houston, the offshore sector is booming and even more mindful of the necessity of safe operations amid an exploration renaissance.

Operators expect a tougher regulatory regime in the Gulf of Mexico going for-ward, one that could lead to some industry consolidation, according to a survey report released at OTC by GL Noble Denton. The survey of 100 senior oil and gas industry executives found that 85% of respondents expect the US regulatory regime to become much tougher over the next 2 years and 61% believe that regime will negatively affect their businesses.

Speakers at OTC sessions echoed those sentiments. The industry should expect new rules about well control equipment, blowout preventers, and production systems, according to Randall Luthi, president of the National Ocean Industries Association.  But he expects overall production from the Gulf of Mexico to continue to increase, and communication between regulators and the industry to continue to improve. E&P activity has rebounded in the Gulf since Macondo. New rigs are being delivered and wildcat wells are being drilled. The most recent deepwater activity report issued by the US government shows a total of 36 floating rigs operating in the Gulf compared with 30 at the time of the Macondo accident, and a total of 51 projects are under way in more than 1,000 ft of water.

In a keynote speech at the recent SPE European HSE Conference and Exhibition in London, Phil Hemmens, managing director of Eni UK, said he believes high-profile accidents such as Macondo and Piper Alpha put a burden on the industry to prove that it can manage its operations safely. The industry has made great strides over the past 30 or so years in raising safety standards and measuring occupational safety performance in a way understandable to regulators and the public. But it does not have key performance indicators (KPIs) that might indicate the potential for a major accident such as Macondo, he said.

Although the industry has some indicators—information gleaned from near-misses or types of hydrocarbon releases—the complexity of deepwater and other projects has made standardizing KPIs difficult. Developing those indicators, and then applying them industrywide, would help both the industry and regulators identify and manage risk at the operational level more efficiently.
The Marcellus Shale Gas Boom Evolves
Authors: Beckwith Robin
Published: February 2015

Marcellus Shale Gas

The Rise in Marcellus Liquids

Ever since its pioneer Renz No. 1 well, recompleted to target the Marcellus shale in October 2004, Range Resources has led trends in the play’s activity. If this holds true, the Marcellus is in for a surge in liquids-rich development.

The company says it is devoting 79% of its 2013 USD-1.3-billion capital budget toward development drilling in the Marcellus shale region. A total of 85% of this spending is being directed toward liquid areas, and 82% of the budget is focused on drilling.

Range states that the “large, liquids-rich window in southwestern Pennsylvania” is the reason “the Marcellus offers the best economics of any large-scale, repeatable play in the country.” The company’s exploitation of this liquids-rich area is well under way. During the first 6 months of 2012, Range produced most of the unconventional gas condensate in Pennsylvania—566,631 bbl—all in Washington County. It almost doubled that production in the latter half of 2012, with 1.1 million bbl, again all in Washington County.

Range has worked steadily over the past 9 years to define the productive limits of the Marcellus. The company believes the industry has achieved this goal through drilling approximately 1,650 wells (1,150 horizontal and 500 vertical). Range says it has drilled 570 wells (511 horizontal and 59 vertical) in the southwest portion of the play. About 110,000 acres of Range’s position in southwest Pennsylvania is prospective for what it calls “super-rich” Marcellus, 220,000 acres for wet gas, and 210,000 acres for dry gas.

Only a handful of other companies have met with success when drilling for Pennsylvania Marcellus liquids—and most production has been moderate to negligible. These include Shell (through SWEPI LLC), Chevron, and ExxonMobil (through XTO), as well as a sprinkling of smaller companies like R.E. Gas Development (a subsidiary of Rex Energy), BLX Inc., Triana Energy, and Northeast Natural Energy. The liquids-rich play is growing in activity in northern West Virginia, with several operators such as Chesapeake, EQT, Stone Energy, Anterro, and Gasstar expanding drilling efforts there.

Sustaining Dry Gas Production: Learning By Doing

Faced with a glut in the US of dry natural gas that keeps Henry Hub Natural Gas Spot prices hovering around USD 3.63/MMBtu, there is a general trend throughout the country away from dry natural gas drilling to liquids-rich plays. And while liquids exploitation is enticing because they command higher prices, they also represent a challenging logistical conundrum. Infrastructure must be in place to transport and process the liquids.
The Middle East's Flourishing Technology Hubs
Authors: Henni Abdelghani
Published: February 2015

Middle East Technology Centers

The Middle East is considered a region that sits on huge, low-cost, easily extract-able reserves of oil and gas and where countries enjoy cash windfalls without thinking about adding value to exploration and production.

But companies and governments in the Middle East are increasingly looking into developments that require investment in technology, managing fields, expanding the resource base, increasing recovery, and even exploring unconventional resources. In addition, local governments see significant upside in building the region’s knowledge-based economy. “We want to leverage our R&D success into new business opportunities in the kingdom” of Saudi Arabia, said Amin Nasser, senior vice president for upstream at Saudi Aramco.

Major companies in the Middle East have started addressing these ambitions through innovation and collaboration, investing in educational infrastructure universities, and hosting firms willing to invest in technology-related businesses. The major centers for research and development (R&D) in the region are the King Abdullah University of Science and Technology (KAUST) and Dhahran Techno Valley (DTV) in Saudi Arabia, and the Qatar Science & Technology Park (QSTP).

Several foreign firms, primarily service companies, have recently begun establishing technology centers in the region to better serve their clients and to more effectively address challenges related to their operations.

Oil and gas research activity is flourishing at DTV located in Dhahran, Eastern Province of Saudi Arabia, which sup-ports local and international companies working to develop their products and services.  Ten technology companies, 10 research centers, and 10 incubated businesses are now operating at DTV, said Amjad Shaikh, a technology transfer executive at DTV and an assistant professor at the King Fahd University of Petroleum and Minerals Department of Chemical Engineering. Companies operating at DTV have been issued 20 product patents, while 121 more patents await approval, he said.

DTV consists of several entities, such as the King Abdullah Science Park, the Innovation Center, Consultancy and Liaison Office, and Business Incubation. These entities work to protect knowledge creation, facilitate industry collaboration, encourage entrepreneurship, support innovation, and enhance knowledge transfer to and from King Fahd University.

“The science park has one of the world’s largest concentrations of top oilfield service companies,” Shaikh said. This is further strengthened by the fact that DTV and its affiliates are located close to Saudi Aramco, the world’s largest oil producer, and King Fahd, generally regarded as the Middle East’s top university for its engineering programs.
Improving Management of Deepwater Oil Drilling Risks
Authors: Coburn Jim
Published: February 2015

Management

BP has borne the costs of the Macondo deepwater drilling accident, but it is not the only firm exposed to risk. Institutional investors are using multiple strategies to find how companies involved in offshore drilling are assessing and man-aging the risks from deepwater drilling operations to ensure that such a disaster is not repeated. They are working to improve risk management practices by engaging directly with companies, analyzing corporate practices, and analyzing the quality of reporting in US Securities and Exchange Commission (SEC) filings and other sources.

Investor Requests for Information

In August 2010, 58 global investors rep-resenting more than USD 2.5 trillion in assets—including the New York State Comptroller, California State Treasurer, Florida State Board of Administration, and the UK-based Local Authority Pension Fund Authority Forum—wrote to 27 oil and gas and 26 insurance companies asking for information on how they manage risks related to offshore operations.

The letters asked oil and gas companies about investments in spill prevention and response systems, contingency plans for managing blowouts, specific lessons learned from the BP spill, con-tractor oversight and selection information, and governance systems. Letters sent to insurers asked how exposure to the oil and gas industry and overall underwriting criteria might be adjusted in light of risks exposed by the spill.

Investors have also engaged companies directly to ensure that management is improving drilling risk management and communicating those changes to shareowners. In 2012, investors filed resolutions related to drilling or refinery risk management with Chevron, Marathon, Cabot, ConocoPhillips, Tesoro, and Valero. The Chevron resolution is typical, asking the board to prepare a report “on the steps the company has taken to reduce the risk of accidents. The report should describe the board’s oversight of process safety management, staffing levels, inspection and maintenance of refineries, oil drilling rigs, and other equipment.” A resolution requesting a report on accident risk-mitigation strategies filed with Valero was backed by 44% of shareholders.
Stuck Coiled Tubing: Risks in a Complex Operating Environment
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 163914, ’Stuck Coiled Tubing: Addressing the Risks in a Complex Operating Environment,’ by Rex Burgos, SPE, and Robin Mallalieu, SPE, Schlumberger, prepared for the 2013 SPE/ICoTA Coiled Tubing & Well Intervention Conference & Exhibition, The Woodlands, Texas, 26-27 March. The paper has not been peer reviewed.

Sticking the coiled tubing (CT)  is a major operational risk when performing a well intervention with CT. Stuck-pipe incidents often result in considerable production delay or, in the worst case, loss of the well. Mechanisms for dealing with stuck pipe are varied. Over the last decade, the profile of wells in which CT intervention has been used has evolved. The operating environment for today’s intervention can be more challenging, involving difficulties in wellbore trajectory, complexities in the completion, and an array of sophisticated tool assemblies that require conveyance. During this period, the approach to stuck-pipe avoidance or prevention has remained more or less unchanged.

Introduction

During the 10-year period of this study, several developments in the manner in which oil and gas wells are drilled and completed resulted in a change in the complexity of performing CT well interventions. An increase in intervention activity in horizontal or highly deviated extended-reach wells was found across most operating areas. The type of completions in several of these wells required running more-sophisticated bottomhole assemblies (BHAs) to achieve objectives similar to those in a less-aggressive well-bore environment. An example is the need to run tractors or vibrators in tandem with more standard tools to reach bottom and perform fill removal in extended-reach wells.

Also, the great depths and complexity of these completions increased the time required to perform most interventions. Thus, there was a need for improving operational efficiency, which typically took the form of performing fewer runs to achieve the intervention objective, usually through the use of multifunction BHAs to eliminate tripping runs to the surface to change the configuration of the tool string. Unfortunately, additional complexity in the tool string, whether through added components or a more-elaborate design, typically added risk, including greater potential for sticking.

Data collected for the period 2001–2010 showed that sticking incidents during CT interventions increased. Comparing data for the first 3 years (2001–2003) to data for the last 3 years (2008–2010), the number of reported sticking incidents increased more than threefold. Because the activity levels for the periods were not identical (increased by approximately 50% from one period to the next), a more-representative measure was found with a jobs-between-incidents (JBI) comparison. The JBI for the 2001–2003 period was 926, while the JBI for the 2008–2010 period was 524, a 43% deterioration in the JBI metric and an undesirable trend for this type of intervention activity.
Low-Frequency Water Hammer for Extended-Reach Applications
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 163883, ’Investigation of Low-Frequency Water Hammer for Extended- Reach Applications,’ by R. Macdonald, SPE, B. Jennings, and G. Vecseri, TeleDrill, prepared for the 2013 SPE/ICoTA Coiled Tubing & Well Intervention Conference & Exhibition, The Woodlands, Texas, 26-27 March. The paper has not been peer reviewed.

Horizontal wellbores typically encounter inefficiencies caused by friction during drilling and completion operations. In severe cases, advancing the bit or downhole tools farther into the hole is almost impossible because of the inability of existing technology and methods to overcome downhole-friction forces. This problem is experienced in drilling, completion, and intervention activities and is particularly acute in coiled-tubing (CT) -deployed bottomhole assemblies. It is proposed that a downhole pressure-oscillation tool be developed that enables managing downhole pressure-oscillation amplitude, independent of flow rate. It also is proposed that such a tool, operating at low frequencies, could simultaneously encode downhole measurements within the pressure-pulse signal.

Introduction

Significant innovation has been applied to the challenge of improving weight transfer and delaying the onset of helical buckling when using CT in the horizontal section of wellbores. Numerous technical approaches have been tried with varying degrees of success and economic benefit. Examples include lubricants; tractors; friction-reduction tools; and larger-diameter, tapered, or hybrid work strings.

Recently, the industry has shown interest in the performance of downhole friction-reduction tools in CT drillout operations. The general operating principle of this class of tools is to create a pressure oscillation at a particular frequency that induces motion in the CT. This motion reduces the friction force, improving weight transfer and extending the reach. The greater the pressure oscillation, the greater the induced motion and friction-force reduction.

The mechanical nature of commercially available downhole friction-reduction tools requires that they be adjusted at the surface to generate a pre-determined pressure-oscillation amplitude, in a defined frequency band, at a given flow rate. Flow rate and pressure amplitude correlate positively, which leads to an increase in backpressure as the flow rate increases and, conversely, a reduced backpressure and friction-force-reduction capability when flow rate decreases.
Technology Focus: Wellbore Tubulars (June 2013)
Authors: McDonough Casey
Published: February 2015

Technology Focus

When the first pipelines moved crude from wellhead to market in the early 1870s, it was difficult to balance the product in the line to the storage tanks at each end. If the receiving station was not ready for the crude, the sending station risked pumping too much product and might have overfilled the receiving station’s tanks. Communications were by telegraph in those days, but telegraph lines were usually run along railroads, not pipelines. Instead of telegraphing what was coming down the pipe so that the receiving station could get ready for the volume, the sending station would open and close a valve and pressures and volumes would be received at the other end. Morse code by pressure waves was used instead of the electrical current and electromagnetism of the Cooke and Wheatstone telegraph. This pulsing is thought to be the beginning of the measurement-while-drilling mud-pulse technology of today. 

Several technological efficiencies have been achieved to increase the data rate of the mud-pulse technology, but they increased the data rate only marginally. Restricting the flow of mud inside the drillpipe through a poppet-and-orifice combination or modulating it through a siren would give longs and shorts like the dashes and dots of Morse code. Negative pulse technology added a small increase in efficiency. It used sharp pressure drops out the drillstring that provided a sharper signature at surface that was tied to time events and a few more bits could be compacted together. Electromagnetic systems send information to the surface with low-frequency electro-magnetic waves. The technology uses the flow of electricity to transmit bits. It has its applications but is dependent on the formation resistivity and depth. Wired drillpipe is a step-change solution for higher downhole data rates. If the cost can become competitive and the product is robust enough, data rates required to send high-definition images will be realized and the choice will exist to increase the data rate to 1 million times that of electromagnetic or mud-pulse telemetry. 

Tubulars are evolving to become data transmitters of increasingly larger band-width. In both the drilling and completion phases, greater bandwidth is required to monitor the stimulation of a well and to drill a wellbore more efficiently. Evaluating position in the lateral while drilling, monitoring drilling efficiencies downhole, and monitoring stimulation efficiencies all require greater bandwidth. Conventional wire and even fiber-optic cable are being used in innovative ways, in harsh conditions, to solve these evaluation issues.

Recommended additional reading at OnePetro: www.onepetro.org.

SPE/IADC 163420 Drillstring-Mechanics Model for Surveillance, Root-Cause Analysis, and Mitigation of Torsional and Axial Vibrations by Deniz Ertas, ExxonMobil, et al.

SPE/IADC 163449 RFID—A Key Enabler in Drilling Automation by Mads Grinrod, Minerals Group, et al.

SPE 157388 New Test for Material Resistance Against Microbiologically Influenced Corrosion by Jeppe Jensen, DTI Oil & Gas, et al.
Wired-Drillpipe Field Trials Reveal Potential Benefits Over Traditional Pipe
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 163560, ’A Summary of Wired-Drillpipe Field Trials and Deployments in BP,’ by Stephen T. Edwards, Chris J. Coley, Nick A. Whitley, Richard G. Keck, SPE, Vishwahnath Ramnath, Tommy Foster, Keith Coghill, and Mark Honey, SPE, BP, prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5-7 March. The paper has not been peer reviewed.

Field trials were conducted by BP on the commercial version of wired pipe with a comprehensive suite of logging-while-drilling (LWD) tools, measurement-while-drilling (MWD) functionality, and rotary-steerable- capability on two Wyoming wells in 2007. Since then, BP has deployed wired pipe commercially in more than 14 wells at four additional locations (Trinidad, North Sea, Colombia, and deepwater Gulf of Mexico), representing a good cross section of drilling conditions and challenges. 

Basics of How Wired Pipe Works

Wired drillpipe incorporates a section of coaxial cable in each joint. The cable passes through a gun-drilled hole in the connection on each end of the joint. Between connections, the cable is encased in a strong stainless-steel sheath, which is held in tension within the inner diameter of the pipe adjacent to, but not bonded to, the inner wall. Figs. 1 and 2 show schematics of the wired pipe.

Inductive coupling enables the signal to pass from one joint to the next, through ferrous coils that are embedded in the pin end of one joint of pipe and the opposing box end of the subsequent joint of pipe. These coils come very close to each other when the connection is made up, but, because the coupling is inductive, they do not need to touch, and insulating material such as pipe dope does not block the signal. However, over many joints of pipe, there is a loss of signal strength, and, for this reason, a battery-powered booster sub is deployed approximately every 1,500 ft. The booster assemblies also provide housing and a connection point for along-string measurements. On the bottomhole-assembly (BHA) end of the drillstring, wired pipe connects to the measurements providers and steering assembly through an interface sub, enabling two-way communication to the network, usually provided by the LWD provider. At the top of the drillstring, the network is connected to surface servers by a data swivel housed in the top drive.

Wired-Pipe-Enabled Applications

Real-Time Imaging. Several different LWD imaging tools are commercially available today. Two types of tools that have been run with wired pipe are the LWD azimuthal density imaging tool and LWD resistivity imaging.
Case Study Examines Safely Exceeding Buckling Loads in Long Horizontal Wells
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 163518, ’Safely Exceeding Buckling Loads in Long Horizontal Wells: Case Study in Shale Plays,’ by S. Menand, SPE, DrillScan, and D. C-K Chen, SPE, Hess, prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5-7 March. The paper has not been peer reviewed.

The general industry perception is that, when drillings or casing strings exceed conventional helical-buckling criteria, they cannot be operated safely in the hole because the risk of failure or lockup is too high. However, some theoretical, experimental, and field case studies have shown that a tubular may be run in the hole even in a buckling state within safe limits.

Introduction

Buckling occurs when the compressive load in a tubular exceeds a critical value, beyond which the tubular is no longer stable and deforms into a sinusoidal or helical shape. Sinusoidal buckling corresponds to a tube that snaps into a sinusoidal shape, and it is sometimes called lateral buckling, snaking, or two-dimensional buckling. Helical buckling corresponds to a tube that snaps into a helical (spiral) shape.

Recent studies have shown that the conventional sinusoidal- and helical-buckling criteria are accurate only in a perfect wellbore geometry because wellbore tortuosity and doglegs play a great role in the buckling phenomenon. An example is illustrated in Fig. 1, which shows that sinusoidal and helical buckling take place simultaneously despite the same compression; doglegs and tortuosity play an important role in the onset of buckling.

Compression on the drillpipe is maximal when tripping in, running casing/liner, or performing slide drilling. Buckling may also occur when drilling with a rotary assembly with a large weight on bit (WOB). The critical helical-buckling load for a rotating pipe may be approximately 50% less than that obtained for a non-rotating pipe. The helical-buckling load is generally the load used in drillstring or casing design to define the limit upon which the tubular might be fully buckled, with the risk of getting stuck or with the risk of large bending stresses that may lead to failure. During well planning, if the compression in the drillstring exceeds the critical helical-buckling load, drilling engineers usually modify the drillstring design until this buckling does not occur. It is widely recognized that sinusoidal buckling is not harmful to a tubular, but helical buckling is generally perceived as a dangerous situation.
New Design of Solid-Expandable Tubular Aids Patching of Hard-To-Reach Casing
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper IPTC 16429, ’Innovative Design of the Solid-Expandable Tubular To Patch the Casing: Area Below the Previously Installed Expandable Tubular,’ by Tao Li, Shan Gao, Qiang Chen, Yiliang Li, Weiye Han, Xiuling Bi, and Qiang Sun, PetroChina, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.

Solid-expandable tubular (SET) is widely used to patch casing and has proved to be cost effective; however, when the damage is directly below an area previously patched, conventional expandable tubular might not be positioned smoothly because of a loss in wellbore size caused by the previously installed tubular. A new design involves putting the expansion tool outside the tubular. As a result, the expansion ratio could be maximized and the tubular without launcher could pass through the smaller wellbore.

Innovative Structure Design

SET technology is well known for its classic structure (Fig. 1). The expansion tool is put inside the tubular and pushed upward by hydraulic or mechanical means. Usually, rubber is used to seal the annular space between the casing and the tubular. This structure has great advantages in the field and has been used widely across the world; however, one significant weakness cannot be ignored. While the expansion tool is inside the tubular, it restricts the expansion ratio. Therefore, this structure is not appropriate for handling some difficult issues. The most common issue is that the casing often needs to be patched more than once. Usually, the patch position is directly below the previously installed SET, making it almost impossible for the conventional patching tool to be delivered in position. The new design was developed to meet this challenge (Fig. 2).

The expansion tool has been placed outside the tubular, powered by a cylinder and piston. An anchor is used to fix the tubular during expansion (Fig. 3a). As the SET is delivered into position, liquid is pumped into the tubing to activate the piston. Because of the anchor, the expansion tool can expand the tubular, and the expanded part is stuck to the casing, sealing the annular space (Fig. 3b). After the initial expansion, the tubular is fixed to the casing and the anchor is no longer needed (Fig. 3c). The same process then could be repeated until the end of the expansion process (Fig. 3d).
AIME, SPE's Parent Organization
Authors: Fattahi Behrooz , Lawrie-Munro Michele
Published: February 2015

AIME

Almost everyone in the oil and gas industry is more or less familiar with SPE and its contributions to the industry. But many may not know that SPE has a parent organization: the American Institute of Mining, Metallurgical, and Petroleum Engineers (AIME).

AIME was established in 1871 in Wilkes-Barre, Pennsylvania, as the American Institute of Mining Engineers. In 1904, AIME became one of the founding societies along with the American Society of Mechanical Engineers (ASME) and the American Institute of Electrical Engineers (AIEE, later IEEE) to form the United Engineering Society. In 1912, the Iron and Steel Division was created, and in 1918, the American Institute of Metals joined AIME, and the new organization, while still AIME, was called the American Institute of Mining and Metallurgical Engineers.

In 1922, the petroleum division of the AIME was formed. AIME continued to grow until 1956 when AIME officially became the American Institute of Mining, Metallurgical, and Petroleum Engineers. During the 1950s, the petroleum membership of AIME grew rap-idly, warranting the formation of SPE as the petroleum industry’s professional society in 1957 with a membership of approximately 12,500. In 1973, AIME started the process of decentralization and, as a result, SPE became a separately incorporated entity in 1985. Today, AIME is a federation of four not-for-profit professional societies: SPE (with more than 100,000 members); the Association of Iron and Steel Technology (15,000 members); the Society for Mining, Metallurgy, and Exploration (14,000 members); and The Minerals, Metals and Materials Society (12,000 members).

AIME operates under a foundation model, governed by an eight-member Board of Trustees, two appointed by each member society. An executive director manages its operation. The presidency of AIME rotates among its four member societies. Its mission is to support its member societies, through exercising fiscal responsibility, distributing funds, facilitating interaction with the larger scientific and engineering community, enhancing collaboration among the member societies, and honoring the legacy and traditions of AIME. AIME’s vision is to be a relevant and valued partner to its member societies. AIME’s principal activities include funding projects and programs through distributions and grant opportunities, providing forums to share best practices and facilitate collaboration among the engineering and scientific community, and presenting awards and scholarships that honor the AIME legacy and recognize outstanding members and promising students.
Emerging Frontiers: Focus on the Subsea
Authors: Spath Jeff
Published: February 2015

President's column

Over the past 6 months, I’ve talked about several emerging geographic and technology frontiers in the oil and gas industry. One of the most exciting and prolific emerging technology frontiers is also geographic in a way—the seafloor of deepwater basins around the world. Since the first installation of a subsea production tree in the Gulf of Mexico in 1961, the surge in the deployment of subsea wells has resulted in significant economic and environmental improvements in deepwater development.

High oil prices, technological developments, and the need to counterbalance declining production in mature shallow-water basins have been driving the move of offshore oil and gas operations into deep and ultradeep (>10,000 ft) waters. Growth in this sector has been momentous over the past few decades. Subsea installations will grow from roughly 2,000 in 2001 to an estimated 8,500 by 2018. Growth in capital expenditure (Capex), driven primarily by Asia, Africa, and the North Sea is estimated to grow by 120% between now and 2018.

Increasingly, operators are cost-effectively targeting reservoirs over a much wider area, tying back subsea wells both to fixed platforms in shallow waters and to floating infrastructure in deeper waters. In fact, capital-intensive ultradeepwater developments are expected to capture 48% of Capex and 23% of tree installations in 2014–2017, in contrast to 37% of Capex and 15% of installations in 2008–2013.
Technology Could Cut CO2 Cost Sharply for Enhanced Oil Recovery
Authors: Henni Abdelghani
Published: February 2015

Technology Update

As oil fields throughout the world are reaching maturity and requiring the use of secondary and tertiary recovery techniques, oil companies are looking for new processes and technologies to extract more oil from these aging fields.

In the next 20 years, an estimated 50% of waterflooded fields will need to shift to enhanced oil recovery (EOR). Carbon dioxide (CO2) has proved to be an almost ideal EOR medium for a broad range of reservoir types and conditions, yielding increases in recovery of up to 15% of oil initially in place.

Most of the experience with commercial CO2 EOR has been gained in onshore oil fields in the United States, particularly in the Permian Basin of Texas, where nearby sources of natural CO2 gas and an extensive CO2 transport infrastructure are available.

“Onshore CO2 flooding is economical at CO2 costs of around USD 35 to 40 per tonne and an oil price of more than USD 75 per barrel,” said Richard Doidge, director of the TriGen CO2 removal technology program at Maersk Oil. “Where natural CO2 sources are not readily available, CO2 may today be sourced from petrochemical and pre- or post-combustion capture plants, for example. However, these capture methods typically yield CO2 prices of USD 80 to 120 per tonne, which would make CO2 flooding uneconomical.”

A ready but limited source of lowcost CO2 can be obtained from facilities, such as ethanol, petrochemical, and gasto- liquids plants, but the bulk of globally emitted industrial CO2 comes from power production and heavy industries, such as steelmaking and cement production.

There are three main approaches to removing or “scrubbing” CO2 from feed or flue gases: precombustion, post-combustion, and combustion. Because of the oxygen required in the combustion mixture, the combustion methods are usually called oxy-fuel processes. The efficiency of these processes depends on, among other factors, the concentration of CO2 in the feed or flue gas and the pressure at which the contaminated gas is treated.
A New Approach to Coiled-Tubing-Integrity Monitoring
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 168303, ’Optimizing Pipe Management With a New Approach to Coiled-Tubing-Integrity Monitoring,’ by Michelle Torregrossa, SPE, Liam Zsolt, SPE, and Mirjam Zwanenburg, SPE, Schlumberger, prepared for the 2014 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 25-26 March. The paper has not been peer reviewed.

With the availability of operational magnetic-flux-leakage (MFL) -measurement devices, operators are now able to see many previously undetectable coiled-tubing (CT) defects as they occur and advance. CT operators can now understand the circumstances that caused these defects, the conditions that worsen them, and the methods that can prevent their progress. This work will present an object-oriented tracking system that allows CT operators to monitor defects as they evolve over time.

Introduction

For many years, an integral part of pipe management has been nondestructive-evaluation (NDE) inspections of CT strings. These inspections exist to complement the use of theoretical-fatigue-life (TFL) tracking and mitigation of pipe failures. It is possible to track fatigue, imperfections, and anomalies during the job. These data should be used to optimize pipe management further in field locations. Despite its availability, the practice of conducting real-time NDE by use of MFL principles during job execution has been quite rare. Because NDE tools are becoming increasingly robust and reliable, this technology can now be used at the wellsite during CT jobs and thus data can be analyzed in real time. Sites in Alaska, for instance, run NDE devices in CT-drilling operations, and implement the findings into their pipe-management practices.
Self-Diverting Acid for Effective Carbonate Stimulation Offshore Brazil
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 165089, ’Self-Diverting Acid for Effective Carbonate Stimulation Offshore Brazil: A Successful History,’ by A.T. Jardim Neto, C.A.M. Silva, R.S. Torres, R.L. Farias, F.G.M. Prata, and L.A.M. Souza, Baker Hughes, and A.Z.I. Pereira, A. Calderon, and E.F. Sandes, Petrobras, prepared for the 2013 SPE European Formation Damage Conference and Exhibition, Noordwijk, the Netherlands, 5-7 June. The paper has not been peer reviewed.

This work describes the positive results experienced when a self-diverting acid system based on a viscoelastic-surfactant (VES) technology was introduced for carbonate-reservoir stimulation offshore Brazil. The self-diverting (SD) VES (SD-VES) promotes viscosity development when the acid comes in contact with the carbonate formation. Since the SD-VES was introduced in this environment in 2009, more than 40 wells have been treated with the system.

Introduction

Matrix acidizing is frequently used to stimulate carbonate reservoirs offshore Brazil. In these treatments, a proper diversion technique is required to direct the treatment fluid to lower-permeability or more-damaged zones and ensure the treatment of the entire production interval. The chemicals developed and used as diverting agents include polymer gels, foams, oil-soluble resins, and rock salt, among others. Offshore Brazil, polymer-based systems have been applied successfully. Such systems are easier to handle than particulates, and diversion is achieved through the formation of natural resistance to viscous flow. Generally, the treatment is divided into three phases: a regular 15-wt% hydrochloric acid (HCl) is pumped first, followed by a gelled 15-wt% HCl, and finally by a pill of insitu- crosslinked gelled 3-wt% HCl. In most cases, several stages are pumped, repeating the three phases in order to cover the entire interval.

Despite the success experienced with polymer systems, concerns about the potential damage to the formation provided an impetus for the successful introduction of a viscoelastic-acid system offshore Brazil.