bluuebunny/crossref_metadata_2025_split huggingface dataset:
Santos Basin, Brazil: Successful Drilling Campaign 2008-2010
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 22336, ’Case History: Performance of a Drilling Campaign in the Santos Basin, Brazil, 2008-2010: A Success Story,’ by Humberto Carrizo, Giovanny Ortuno, and Tarcilio Dutra Neto, Repsol Sinopec Brasil S.A., prepared for the 2011 Offshore Technology Conference Brazil, Rio de Janeiro, 4-6 October. The paper has not been peer reviewed.
The evolution in well design and continuous-improvement actions are reported for the execution of five shallow-water and deepwater wells drilled by Repsol using a third-generation semisubmersible rig during 2008–2010. As part of the continuous-improvement approach, the quality-assessment/quality-control (QA/QC) procedures were tightened throughout the campaign. The proper use of after-action reviews at the completion of each well phase was paramount for the lessons learned from each well and their application to subsequent wells.
Introduction
The exploration-drilling campaign during 2008–2010 in the Santos basin used a moored semisubmersible drilling rig and was the first campaign in Brazilian waters by Repsol Sinopec Brasil. The blocks where these operations were performed are approximately 180 naut miles from the shore base. These wells were post-salt prospects in shallow and deep waters. The map in Fig. 1 shows the well locations for Wells A, B, C, D, and E. In the lower right of the figure is the order in which they were drilled, together with the respective water depth. The complete paper details well design and well operations from spud to total depth (TD).
Actions considered key for performance achievements are framed by a continuous-improvement process, with tangible actions to reduce total time on well, and can be summarized as in Fig. 2. The total time on well can be reduced within the two stages of the well-construction process.
During well planning: Make well-design improvements and/or plan application of a new technology.
During project execution: Make well-operation improvements to remove invisible lost time (ILT) and reduce non-productive time (NPT).
Well Planning
Well-design activities carried out by the multidisciplinary project team are governed by the company’s well-construction process (WCP). The WCP is a gated four-phase process: visualization, conceptualization, definition, and execution. At the end of each phase, a gate-event meeting occurs in which a multidisciplinary technical team, based at headquarters, appraises information from the phase and then, depending on the results, decides whether to continue to the next phase.
The WCP receives well data from the geological and geophysical team, and these data are essential input for well-design activities until the well design is fixed at the second gate and the basis of design is delivered. Design activities end with the drill-well-on-paper document. At the third gate, the drilling program is signed as the main deliverable before starting well operations.
Hybrid Rotary Steerable System Delivers Higher Build Rates and Smoother Holes
Authors: JPT staff _ 
Published: February 2015

Young Technology Showcase
Every drilling engineer’s dream would be to deliver more complex well profiles and smoother, more consistent boreholes in less time—ideally in a single run—eliminating the need to trip out of hole. The problem is that conventional positive displacement motors (PDMs) and rotary steerable systems (RSS) both exhibit limitations in different drilling scenarios.
Industry Challenges and Needs
Downhole motors, for example, are capable of delivering reliable, very high dogleg well profiles. However, because the drillpipe alternates between rotating and sliding, rates of penetration (ROPs) are low and hole quality is tortuous, increasing the potential for stuck pipe.
On the other hand, fully rotating RSS deliver smoother wellbores at higher ROPs than PDMs, reducing drilling time by as much as 50%. However, the maximum build rate of a typical RSS is only 6 to 8 deg/100 ft, and much lower while drilling soft formations, enlarged holes, or hard interbedded stringers at high angles to the wellbore. For well profiles with high build rates, an RSS may be used for the vertical and lateral sections while motors must be used between the kickoff and landing points. This requires at least three bottomhole assemblies (BHAs) and multiple trips out of hole.
To reduce risks while saving rig time and costs, drillers would prefer the hole quality and performance of an RSS combined with the high dogleg capability and steering assurance of a PDM.
To meet operators’ growing needs both in unconventional shales and difficult formations, Schlumberger developed the PowerDrive Archer high build-rate RSS. In a single run, the technology can deliver well profiles previously possible only with motors. By improving borehole quality and reducing tortuosity, it minimizes the risk of stuck pipe and facilitates the deployment of casing, sleeves, and completion equipment (Fig. 1). It can perform openhole sidetracks and drill deeper before kickoff than other RSS, maximizing reservoir exposure and increasing potential production.
Description, Development, and Deployment
The high build-rate RSS represents a breakthrough in steering control. The RSS has been in use since the late 1990s. However, it could not deliver the 8-to-12-deg/100-ft build rates necessary for typical well profiles in unconventional shale plays. Due initially to rapid increases in shale drilling, Schlumberger began development in 2007 of a new RSS aimed at roughly doubling the maximum build rate of previous tools.
Technology Focus: Natural Gas Processing and Handling (April 2013)
Authors: Hobbs George 
Published: February 2015

Technology Focus
On the 201st anniversary of the founding of the first commercial gas operation, the Gas, Light and Coke Company (later British Gas), the future for natural gas has never looked better.
In 2011, global natural gas reserves increased to the equivalent of approximately 80% of oil reserves. Unconventional gas sources are now a large proportion of US natural gas supply, particularly tight and shale gas (30%) and coalbed methane (CBM) (6%). Natural gas in 2011 contributed 24% of worldwide energy consumption, compared with 33% for oil and 30% for coal. CBM is also an important source of energy, particularly in eastern Australia, where three CBM liquefied natural gas (LNG) plants are under construction and a fourth and possibly a fifth are proposed. CBM and Western Australian conventional gas are set to make Australia the largest LNG exporter in the world within 5 years.
Gas is likely to dominate energy supply because of improved available reserves, lower carbon intensity, lesser environmental footprint, and long-term zero-carbon goals involving CO2 capture and sequestration. In addition, removal of contaminants such as water, hydrogen sulfide, and mercury has been improved through nano and smart technologies. Safety improvement research and development is another key objective of the industry.
Underground gas storage is now in greater usage for supply security, with smart wireless technology becoming increasingly involved in its management.
Six floating LNG offshore production facilities are expected to come on stream within this decade, five in Australasia and the other in offshore Malaysia.
The potential is for very remote deep small offshore gas reserves to be economically exploited using floating compressed natural gas (FCNG) technology. Because of the massive effect of US unconventional gas production on LNG imports, gas producers such as Trinidad are reportedly reviewing their future gas export strategies and considering FCNG.
Commercial exploitation of the known massive methane hydrate reserves is still some time off. However, research in hydrate control is advancing the understanding of hydrate physical chemistry. This research also has helped conventional deepwater gas production where subsea/downhole heating now is used to prevent hydrate blockages. Early last year, the US and Japan successfully completed a field trial of methane production from hydrates on the Alaska North Slope.
To find out more, attend the Offshore Technology Conference in Houston, 3–6 May 2013.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 161583 The Optimization of Natural Gas Transportation by Michael J. Economides, University of Houston, et al.
SPE 162938 Gas Transmission Market: New Trends Around the World by Gina Vega Riveros, Reservoir Consultant
SPE 151161 Control Loop Performance Management To Improve Business Objectives by Zhenhai Liu, ADGAS, et al.
25,000-psi 500°F Packer-Seal System
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 159182, ’A Completion-Technology Milestone - The First 25,000-psi 500°F Packer-Seal System,’ by James Doane, Guijun Deng, SPE, and Scott Collins, SPE, Baker Hughes, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-10 October. The paper has not been peer reviewed.
As operators continue to drill into deeper and more-extreme formations, the demand for technologies suited to these environments increases. Much effort has been invested across the industry to overcome obstacles in developing safe and reliable completion tools that are qualified for conditions in excess of 15,000 psi and 450°F. A technological milestone was set recently in packer-seal-system development―the first 25,000-psi, 500°F packer-seal system.
Introduction
The criteria for designating fields as high-pressure/high-temperature (HP/HT) fields have changed over the years. Early on, HP/HT fields were those with pressures greater than 10,000 psi and temperatures higher than 300°F. During the last 20 years, the HP/HT designation changed to 15,000 psi and 350°F, an environment in which technical operational challenges have been mostly overcome. Other terms have come into use to designate new HP/HT thresholds. Extreme-HP/HT fields have pressures up to 20,000 psi and temperatures up to 450°F, and ultra-HP/HT fields have pressures up to 30,000 psi and temperatures up to 550°F.
High gas prices and the search for hydrocarbons in deeper formations are key drivers for development of new HP/HT completion technologies. Extreme-HP/HT wells are being drilled in the Gulf of Mexico, on the shelf and in deep water. Many of them have a total depth of more than 25,000 ft and exhibit reservoir pressures approaching 20,000 psi and temperatures exceeding 450°F. There is limited availability of specialized tools for these pressures and temperatures. In ultra-HP/HT environments, there are many technical difficulties that must be overcome, including seals and polymers, metallurgy, and test facilities.
Concept Design
The objective of this project was to design a sealing system for a packer for 7.625-in., 51.2–52.8-lbm/ft casing. The sealing system must be rated to 25,000 psi at 500°F. Qualification testing was conducted with nitrogen to all rating-envelope points at 500°F with a cool down to 250°F. To enhance performance in as-rolled casing and ultra-HP/HT applications, two existing systems were considered for the new seal design. System A is rated to 15,000 psi and 350°F. System B is rated to 15,000 psi and 500°F. In addition, the System-A packer has been qualified for applications with grooved or poor conditions on the inside diameter (ID) of the casing.
Renewing Mature Shale Wells Through Refracturing
Authors: Jacobs Trent 
Published: February 2015

Refracturing opportunities
In what may become Act Two for the North American “shale revolution,” some operators are returning to their mature shale wells to refracture, or restimulate, the rock to accelerate the rate of production and enhance the ultimate recovery of trapped hydrocarbons. Refracturing is not a new technique and has been applied for many years in tight rock and vertical wells. But now producers want to apply refracturing to a large inventory of unconventional wells suffering from low production because of ineffective initial completions. Refracturing could also serve as a countermeasure against the characteristically steep decline rates of shale wells. A few years after coming on-stream, most horizontal shale wells produce at a fraction of their initial rate, yet large volumes of oil and gas remain in the rock that could be produced through refracturing.
Those involved expect shale well refracturing activity in the United States and Canada to increase steadily as companies figure out how to optimize the mechanics of the operation. Their optimism is based on some early success stories, and the sheer number of possible refracturing opportunities that exist. “Over these next 2 years, the industry will be sharpening their pencils on how and where they are going to (refracture), and then they are going to do it because the potential is tremendous,” said Ibrahim Abou- Sayed, founder of a Houston-based company called i-Stimulation Solutions that offers upstream engineering and consulting services.
However, some companies are sitting it out until newer technology overcomes some of the challenges involved with refracturing to make it an easier operation to carry out. Tim Leshchyshyn, founder of a Calgary-based company called FracKnowledge that maintains a database of fracturing information, characterizes refracturing as a “large, complicated topic” that needs more research and development to become a reliable technique. “For many of the candidates that need to be refractured, the industry is short on technology to do so,” he said. “I think there are some tools out there that help, but there is still a lot of room for technology development to make it easy and highly successful.”
Testing of Distributed-Temperature Sensing in Flexible Risers and Flowlines
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 23948, ’Full-Scale Testing of Distributed-Temperature Sensing in Flexible Risers and Flowlines,’ by Nick Weppenaar, Thomas Iversen, and Bo Andersen, NOV Flexibles, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.
This paper presents results from full-scale testing of a flexible riser equipped with embedded sensors for distributed-temperature sensing (DTS). Testing includes monitoring of accessories mounted on the riser, monitoring of hot spots such as trenched sections of the riser, and detection of breaches of the outer sheath. Applications of such a condition-monitoring system to riser-integrity management (RIM) and production optimization are worth examining.
Introduction
With the increasing use of flexible-pipe technology—driven by the move of new offshore fields to deeper, more-marginal, and more-challenging conditions— the need for systematic management of the flexible pipes is becoming more apparent. In particular, the full implementation of RIM plays a vital role in ensuring an efficient and safe operation. Riser-condition monitoring and inspection form an important part of integrity management, together with processing and analysis of the monitored data. In that respect, the recently developed technology within optical-fiber monitoring offers unique possibilities for quantifying the integrity of flexible risers during their service life. The advantage of an embedded monitoring system is the ability to survey the riser condition continuously, thus enabling operators to detect potential damages in a timely fashion. The embedded system will allow monitoring in critical areas (e.g., under a bend stiffener or inside an I-tube) where access is limited for externally mounted monitoring systems.
Temperature-Monitoring System
The temperature-monitoring system is a DTS system that uses a standard multimode optical fiber to measure the temperature at all points along the fiber with a given spatial resolution. The principle of implementation into a flexible pipe is shown in Fig. 1. The fiber is mounted on top of the outer tensile layer while being protected from crushing forces. The specific implementation that has been achieved allows for temperature measurements with a spatial resolution in the longitudinal direction of the pipe of approximately 8 cm. Currently, this can be implemented in pipes that are up to approximately 5 km in length, and the sample time can be as fast as 10 seconds per fiber. If a longer pipe length needs to be monitored, this can be achieved at the expense of spatial resolution or temperature resolution.
For the present series of tests, the fiber length is approximately 200 m, which allows for a high temperature resolution. The system measures every 10 seconds, with a temperature resolution of approximately 0.1°C and a spatial resolution of approximately 15 cm.
Innovative HP/HT Drilling Practices in Malaysia: A Case Study
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166110, ’Successful HP/HT Drilling Through Innovative Practices: Sharing a Case Study of a Deep HP/HT Well,’ by M. Syazwan, SPE, Y. Yap, SPE, L. Umar, SPE, and M.M. Pepple, SPE, Petronas Carigali, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed.
Despite a short 18-month planning time and very limited geological data, the TTD-1 high-pressure/high-temperature (HP/HT) exploration well in East Malaysia’s Block SK was drilled successfully to its technical limit by adopting innovative practices. Various technical challenges were overcome, including an abnormally steep pressure ramp, high overbalance, and high temperatures.
Introduction
Malaysia has a relatively low number of offshore HP/HT wells drilled by various operators since the 1990s. In the last few years, a series of successful HP/HT discoveries has prompted operators to focus on this area. The major domestic operator began its first HP/HT exploration drilling in 2008.
In the 2012 HP/HT exploration campaign (Fig. 1), the operator of East Malaysia’s SK Block and their partners successfully drilled an HP/HT reservoir at a depth of 4830 m. TTD-1 was the deepest well of its kind drilled by this operator in Malaysia. The undisturbed-pore-pressure estimate was approximately 14,000 psi, with a maximum temperature of 325°F. Significant gas was discovered throughout the target reservoirs.
TTD-1 was the second well drilled in the two-well HP/HT campaign in 2012. The well was spudded on 7 May 2012 and plugged back on 5 November 2012. The well was successfully production tested in both the normal and HP/HT reservoirs.
Well Challenges and Mitigation
This section outlines a number of the issues faced in the drilling of this well. For a full discussion of these issues, please see the complete paper.
Unreliable Offset-Well Data in HP/HT Section. The availability of reliable data up to the start of pressure ramp helped the planning of the non-HP/HT section. For the HP/HT section, there were no data in any of the surrounding wells that could help in modeling the pore pressure and fracture gradient as inputs for well design. The key challenge was in understanding the overpressure mechanism.
Intelligent-Well Completions in Agbami: Value Added and Execution Performance
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 20191, ’Intelligent-Well Completions in Agbami: A Review of the Value Added and Execution Performance,’ by Adekunle Mojeed Adeyemo, Chris Aigbe, Ike Chukwumaeze, SPE, David Meinert, SPE, and Steven Shryock, SPE, Chevron Nigeria, prepared for the 2009 Offshore Technology Conference, Houston, 4-7 May.
Use of intelligent-well-completion (IWC) technology has grown, even with perceived risks associated with installation and longevity of the systems. In the Agbami field, offshore Nigeria, for which 80% of the development wells are planned with IWC installations, understanding these risks was key in justifying IWCs. The methodology used to quantify the realizable value from zonal control and data acquisition and a review of the execution performance for the initial IWC wells are presented.
Introduction
First production from the Agbami field was 29 July 2008, and it was producing at 140,000 BOPD at the time of writing. Peak production of 250,000 BOPD (not accounting for facilities downtime) was expected by the end of 2009. The Agbami field, discovered in 1998, is 70 miles offshore Nigeria at a water depth of approximately 5,000 ft.
The field is a northwest/southeast-trending doubly plunging anticline, with a significant thrust fault through the crestal axis of the structure. As Fig. 1 shows, the field has four main reservoirs: 17MY, 16MY, 14MY, and 13MY. Approximately 80% of the field in-place volume and reserves are in the deepest sand (17MY), having average porosity of 18% and average permeability of 270 md.
The field-development plan has 38 subsea wells (including 20 producers, 12 water injectors, and six gas injectors) tied back to a floating production, storage, and offloading (FPSO) vessel through subsea flowlines. The drilling-and-completion program is spread over three development-drilling stages. The project is in Stage 1, with eight producers and two gas injectors on line. Pressure maintenance will be by peripheral water injection and crestal produced-gas reinjection to ensure compliance with a “no flare” policy.
Geologic and Engineering Considerations
The field has multiple lobes within each major reservoir. Although these sand lobes, or zones, are in pressure equilibrium geologically, the vertical/lateral connectivity under dynamic conditions is uncertain. Therefore, waterflood and gasflood fronts are likely to advance through the reservoirs at different rates, leading to conformance issues. To optimize field performance and recovery, IWCs with downhole control valves are installed in the Agbami wells. The system will provide zonal information and control of production from and injection into the completed subreservoir zones. IWCs will enable zonal production/injection management for optimal field development and oil recovery.