bluuebunny/crossref_metadata_2025_split 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 The paper has not been peer reviewed.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.