bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Focus: Coiled Tubing Applications (June 2010)
Authors: Misselbrook John 
Published: February 2015

Technology Focus
I guess it is no surprise to the people who manufacture coiled tubing (CT) or to those of us in the CT-service industry who actually buy it, but CT is getting bigger. After a decade during which the most common size was 1½ in., the position changed in 2008 when 1¾ in. finally took top spot. Only 1 year later, 2-in. CT took the pole position.
What, might you ask, is driving this growth in pipe diameter? The answer is: “Horizontal wells.” In the past few years, we have seen explosive growth in the number of horizontal wells drilled, with much of that growth occurring in the North American shale market.
However, the increase in pipe size is driven not only by an increased number of horizontal wells but also because lateral reach is increasing and because completion methods are evolving. Tight-gas-completion methods routinely encompass techniques that use CT for perforating, composite-plug mill-outs, fracture-port ball-seat mill-outs, and fracture-sand cleanouts. The larger-diameter CT is required for greater lateral reach and to enable adequate weight on bit for effective milling operations. Also, because solids removal still requires the same fluid-circulation rates while strings are getting longer, then inevitably, CT diameters must increase to keep surface injection pressures manageable.
Bigger, heavier strings inevitably cost more; and because of equipment-size limitations, these strings are subjected to greater bending strain, which in turn results in a shorter working life. One might imagine that we could be reaching an economic limit on string size, but in fact there currently is no sign that this trend is abating. So, is the answer just to build bigger and bigger equipment? One risk of concentrating solely on the CT handling equipment is that the equipment becomes increasingly focused on specific well types and applications, and, in turn, CT loses its versatility for everyday intervention operations.
Right now, the jury is still “out,” but it remains a question of whether the various technology initiatives aimed at extending CT horizontal reach will ever meet the operators’ expressed desire for ever-longer horizontal wells and, in turn, how that will influence the CT industry.
Coiled Tubing Applications additional reading available at OnePetro: www.onepetro.org
SPE 130632 • “Deliquefication of South Texas Gas Wells Using Corrosion-Resistant Coiled Tubing: A 6-Year Case History” by K.L. Poppenhagen, SPE, ConocoPhillips, et al.
SPE 130625 • “New Field in East Siberia: Challenges of Performing CT Operations in Vankorskoe Field” by V. Bochkarev, Rosneft, et al.
SPE 130579 • “Laminar and Turbulent Friction Factors for Annular Flow of Drag-Reducing Polymer Solutions in Coiled-Tubing Operations” by C.C. Ogugbue, SPE, University of Oklahoma, et al.
Fiber-Optic-Enabled Coiled Tubing Used To Access and Stimulate a Trilateral Oil Producer
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 126730, ’First Worldwide Application of Fiber Optic Enabled Coiled Tubing With Multilateral Tool for Accessing and Stimulating a Trilateral Oil Producer, Saudia Arabia,’ by Ahmed Al-Zain, SPE, Rifat Said, SPE, Salman Gamber, and Saad Al-Driweesh, SPE, Saudi Aramco, and Khzam Al-Shahrani, SPE, and Jan Jacobsen, Schlumberger, originally prepared for the 2009 Kuwait International Petroleum Conference and Exhibition, Kuwait City, Kuwait, 14-16 December.
Recent advances in coiled-tubing (CT) technology enable rigless interventions of complex wells while acquiring real-time downhole measurements. The fiber-optic-enabled CT (FOCT) provides combined services of data acquisition and running other CT tools required for well treatments. The fiber-optic telemetry system consists of a pump-through bottomhole assembly (BHA) with a casing-collar locator (CCL), pressure and temperature sensors, optical fibers inside CT, and a surface readout unit.
Introduction
Horizontal wells have become more commonplace in many Saudi Aramco fields. Recent advances in drilling and completion practices enable more-complex wells with various types and shapes, such as extended-reach wells, bilaterals, multilaterals, and maximum-reservoir-contact (MRC) wells, to be drilled. Benefits of drilling these wells include reduction in development and operating cost because of the smaller number of wells and improvement in reservoir performance and management. These complex wells are drilled for various reasons and many objectives, which may include but not be limited to increased production, enhanced reservoir characterization, improved sweep, maximized recovery, and to ensure efficient reservoir management.
Background
Well-A was drilled and completed as a trilateral openhole oil producer in 2008. The well was cased with 95/8-in. casing to the top of the producing reservoir at 6,220 ft measured depth (MD). An 8½-in. hole then was drilled directionally 3,000 ft inside the reservoir. A 7-in. liner was run and cemented at 9,220 ft MD. The main bore (L-0) then was drilled successfully to a total depth (TD) of 13,040 ft MD. After that, Lateral-1 (L-1) was drilled, after opening a casing window at 7,987 ft MD, to 11,350 ft MD. Following that, Lateral-2 (L-2) was drilled from a casing window at 6,422 ft MD to 9,786 ft MD. Figure 1 in the full-length paper shows trajectories of the laterals.
The well was completed with 4½×3½×27/8-in. tubing and equipped with an electrical submersible pump (ESP) to produce the well. The ESP assembly has a bypass (Y-tool), that allows normal well interventions and other well surveys. The minimum inside diameter (ID) is 2.441 in. downhole in the tail pipe. After completion, the well was flowed for cleanup by the ESP, but it was found unable to flow, indicating severe formation damage.
En Route: The Big Crew Change: It's Now!
Authors: Labastie Alain 
Published: February 2015

President's column
The so-called “big crew change”—the retirement of a large number of experienced professionals and their replacement by a younger generation—has been widely debated during the last 10 years or so, including at many SPE conferences and in the columns of JPT. However, there is something new and very important: this big crew change has actually begun. How is the industry doing in this critical transition?
First, the companies are hiring a lot of young people. This is good news, but I am not sure we are hiring enough to meet our future needs. As I discussed in this column a couple of months ago, our future production will become more difficult and will require more efforts. More human brainpower will be definitively needed, and our industry may become slightly more staff intensive, which is a reversal from the historic trend. In addition, many of our activities will have more important technology and science components. Examples of such activities are seismic processing and interpretation, with more subtle traps and more difficult subsalt plays; EOR, with the need for advanced interface science for chemical flooding; and production operations, with difficult flow assurance issues in deepwater fields.
This means that we will need a more diverse staff—people with broad abilities who are able, for example, to manage a development project some day. This is the traditional petroleum engineer profile. But we also will need people with a focused, in-depth competence to address the type of issues I mention above, and which are relatively new in our industry.
So the new generation will be there for us to access. What about issues related to the loss of many experienced people? I remember having read a column in JPT where a very interesting observation was made: If we look at the global drilling activity in the past 20 years, we can clearly see a correlation between nonproductive time (NPT) and years of experience (average) of the drilling crews; staff with less experience makes more mistakes and loses more time. That is not a big surprise—after all, it is well known that making mistakes helps to build experience. This type of observation is reported only for drilling, because NPT is carefully measured and monitored only for drilling activities. The story no doubt is the same for all our activities, from geosciences to production operations; it just is not measured.
Q&A with Anon Sirisaengtaksin, President and Chief Executive Officer, PTTEP
Authors: Sirisaengtaksin Anon , Donnelly John 
Published: February 2015

Q&A
What is the current energy balance in Thailand for crude oil and for gas? What is the projected future energy balance?
Thailand is an energy importer. We can produce about 44% of our total consumption of crude oil and natural gas. Most of our crude oil imports come from the Middle East. Only 120,000 b/d of crude oil was produced indigenously. We also exported 210,000 b/d of refined products because of a surplus in refining capacity. Natural gas was mostly used for electricity generation. About 79% of natural gas was produced domestically while the rest was imported from Myanmar.
Energy demand will continue to grow to support our economic growth. In 2011, crude oil and natural gas demand is expected to increase by 3% and 10%, respectively. To meet the increasing energy demand, we are extensively exploring and developing more energy resources, both domestically and internationally. Moreover, Thailand will start importing LNG beginning this year. Renewable energy will also play a more important role to serve our national policy of energy diversification.
What is PTTEP’s core exploration and production strategy?
PTTEP’s long-term vision is to become a leading Asian exploration and production company with an aspiration to reach production output of 900,000 BOED by 2020. PTTEP will focus on:
Sustainable growth through growing aggressively in focused countries, developing floating LNG production, and strategic mergers and acquisitions
Asset value maximization by prolonging our production plateau and instituting portfolio management and funding
Organization capability enablers with a focus on streamlining business processes, optimizing resource allocations, developing staff’s overall capabilities, and preparing management and key staff for the company’s business expansion
What is PTTEP’s crude oil and gas production break-down in Thailand and outside of Thailand?
PTTEP has invested in 44 E&P projects in 13 countries, with 19 projects being domestic and 25 projects being overseas. Most of our current production projects are located in Thailand; therefore, in 2010, our petroleum production averaged 300,000 BOED, with a ratio of 80% domestic and 20% international.
Use of High-Strength Coiled Tubing in High-Pressure/High-Temperature Perforating Operations
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 143079, ’Use of High-Strength Coiled Tubing in High- Pressure/High-Temperature Perforating Operations,’ by K. Makris, SPE, and D.A. Barclay, Halliburton, and W.D. VanArnam, NOV-Quality Tubing, originally prepared for the 2011 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 5-6 April. The paper has not been peer reviewed.
A major operating company demonstrated interest in the development of high-strength (greater than 125,000-psi yield) coiled tubing (HS CT) for use in high-pressure/high-temperature (HP/HT) fields in the central North Sea. The objective of the operator was to perforate underbalanced with CT using as much as 1,700 ft of guns in one run. The CT had to be sufficiently strong to avoid collapsing while pulling the weight of the bottomhole assembly (BHA) and the string from the working depth.
Introduction
During last 2 decades, more unconventional reservoirs have been targeted, such as those in HP/HT fields. An HP/HT field typically has bottomhole pressure (BHP) greater than 10,000 psi and a bottomhole temperature greater than 300°F.The reasons for targeting these fields includes the high yield of hydrocarbons they offer, which justifies the high drilling and completion costs, and the depletion of the more-conventional reservoirs in areas with well-established oilfield-support services, meaning that this already-established network can offset the increased well costs.
The range of well services used in HP/HT fields includes the provision of CT services, which have proved to offer a popular way to perform certain operations in these fields, such as deploying tubing-conveyed-perforating (TCP) guns. Often, the weight of the BHA and/or the wellhead pressure after perforating prohibits running perforating guns on wireline. On the other hand, using the rig blocks to deploy, run in hole, and reverse deploy the guns can be time consuming and costly. Hence, CT often can provide a carrier solution and perform such a task faster than the rig because it is stronger and has increased potential for wellbore access when compared to wireline. However, CT is limited by the weight it can pull and the differential pressure (CT annulus vs. CT pumping pressure) it can sustain. Exceeding these limits can result in a CT failure and result in a costly and time-consuming fishing job, or even a well-control situation. While more HP/HT fields are being developed, operators are considering the use of CT to perforate deeper wells with higher wellhead pressures. For the well-intervention industry to rise to the task, the need for stronger CT is obvious.
Extending Well-Productivity Life in a High-Pressure/ High-Temperature Tight Gas/Condensate Carbonate Reservoir by Acid Refracturing
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142444, ’Extending Well- Productivity Life by Acid Refracturing in a High-Pressure/High-Temperature Tight Gas/Condensate Carbonate Reservoir in a Jurassic Formation of Northern Kuwait,’ by Mir Kabir, SPE, Qasem Dashti, SPE, J.R. Singh, SPE, and San Prasad Pradhan, SPE, KOC, and Ikhsan Nugraha, SPE, Liu Hai, and Hamed Al-Ghadhban, Schlumberger, prepared for the 2011 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 31 January- 2 February. The paper has not been peer reviewed.
Productivity of the subject well, which had been on production for 3 years after an initial acid-fracture treatment with almost 90% of its cumulative production occurring during the last year, was declining faster than expected. Review of the well’s performance indicated two possible causes: reservoir-pressure decline and reduced fracture-length/conductivity ratio. Acid refracturing was chosen to restore the well’s productivity by extending the fracture half-length to enhance fracture conductivity. The results showed that the productivity index (PI) increased by a factor of 2.5 during the post-treatment production test. However, after 3 months of production, this declined to 1.2.
Introduction
Several major fields in north-ern Kuwait, including Sabriyah, Raudathain, Umm Niqqa, Bahra, and Dhabi, produce gas from the Jurassic Middle Marrat formation, an important carbonate reservoir. Typical depth is 14,000 ft, reservoir pressure ranges from 10,000 to 12,000 psi, and the bottomhole static temperature averages 275°F. The Middle Marrat formation is mostly limestone (calcite&gt;90%) with minor dolomitization. Only traces of clay and silt are found. High heterogeneity, both laterally and vertically, has been reported. Core permeability matches log permeability, and the high permeability value obtained from the core could be the result of induced fractures. Pressure-transient analyses of some wells showed dual-porosity behavior with low matrix permeability. Generally, the absolute matrix permeability is less than 1 md. The production mechanism is a combination of matrix and natural-fracture permeability.
Acid Refracturing
In regions where acid fracturing is common, there are questions that arise. When is the best time to refracture? What is the justification to repeat the treatment? If there is justification, what needs to be done differently in the subsequent treatment? The decision usually relies on the post-treatment production behavior compared with the pretreatment condition.
Coiled-Tubing and Jointed-Tubing Hybrid String - A New Approach to Well Intervention
Authors: JPT staff _ 
Published: February 2015

Young Technology Showcase
As oil reserves mature around the world, oil companies look to improve the recovery of existing assets and to tap into unconventional reserves such as shale gas and tight gas. Coiled tubing (CT) and jointed tubing (JT) have progressed to larger sizes and premium material grades to adapt to these new and extended applications. However, some situations, such as long horizontal or ultradeep wells, remain where either the CT or JT is unable to provide the required reach efficiently and safely. Combining CT and JT can bring the flexibility of CT to extended-reach horizontal wells.
Typical well intervention operations present several challenges, including equipment and reel availability, transportation issues, achievable flow rates, and the ability to reach the target depth of the well. CT is prone to sinusoidal buckling and eventual lockup in deviated and horizontal wells. This means that friction-reducing agents or mechanical aids such as tractors may be necessary to reach target depths. Smaller CT reduces the flow rate that can be achieved and requires higher horsepower to overcome fluid friction. JT, on the other hand, is larger and heavier than CT but requires constant making and breaking of connections during trip in and trip out, which requires redundant safety measures and reduces the effectiveness of downhole operations.
In shale plays, operators have determined that laterals in excess of 10,000 ft and more than 30 fracturing stages are necessary to maximize production and achieve the desired return on investment. These wells are challenging to complete using only CT.
PowerReach Service
Boots & Coots, a Halliburton service, developed PowerReach, which combines CT and JT to form a hybrid string that offers the best of both. The resulting string allows for greater depth for long horizontals, high flow rates when using larger CT, and a smaller equipment footprint.
The PowerReach system consists of JT at the bottom and CT on top to have the stiffness and weight of the JT at the bottom of the string and the freedom to move the CT portion on top without making connections. The length of CT depends on the length of the lateral or the distance from the first to the last section being treated. This ensures that the string can be moved freely without making a connection. Fig. 1 shows the setup of a hybrid unit on location, including a reel trailer, rig assist unit, and tower with tubing guide.
Targeted Fracturing Using Coiled-Tubing-Enabled Fracture Sleeves
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 154391, ’Reducing Operational Time, Fluid Usage, Hydraulic Horsepower, Risk, and Downtime: Targeted Fracs Using CT-Enabled Frac Sleeves,’ by Luis Castro, SPE, Thomas Watkins, SPE, Brian Bedore, SPE, and Robert Holt, Baker Hughes, and Greg Manuel, Pioneer Natural Resources, 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.
Unconventional reservoirs are an increasingly important part of the hydrocarbon production pool in North America. Because reservoir conditions typically require hydraulic fracturing for economical production, a significant amount of resources are focused on making the fracturing process faster and more efficient and on lowering its environmental impact. A novel technique to create targeted annular hydraulic fractures rapidly involves deploying an activation tool on coiled tubing (CT) to open fracture sleeves in a horizontal well. The new technology uses fracture sleeves that are activated swiftly using a CT bottomhole assembly (BHA). The system, already used in thousands of fracturing stages in Canada, speeds up the completion process, uses less fluid, minimizes risks, and reduces overall downtime.
Introduction
Unconventional reservoirs in the United States are commonly stimulated using what is known as the “plug-and-perf ” (P&P) method. This method requires a tubing-conveyed perforating (TCP) device run, typically on CT, for the first stage to open a conduit for pumping down the casing. The first stage of the fracturing treatment is then pumped down through the open perforations. Once completed, a composite plug and perforating guns are run on wireline to isolate the first fracture stage and to perforate intervals in the second stage (each interval is commonly referred to as a “cluster”). Running wireline in horizontal wells requires pumping fluid from surface to push the wireline BHA through the wellbore like a piston. After retrieving the wireline from the well, the subsequent fracture treatment is pumped. This process is repeated until all stages are completed. After the fracture spread moves off of the location, a CT unit is commonly brought in to mill the composite plugs and allow the well to produce.
Although this method is the one most commonly used, it has drawbacks. P&P fracs are time consuming: They require numerous days on location to prepare the well (i.e., running the TCP device, known as a toe-shoot), complete all the stages designed for the fracturing treatment, and finally mill the plugs.