bluuebunny/crossref_metadata_2025 huggingface dataset:
Pushing the Extended-Reach Envelope: Drilling a Record-Reach Well
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 151046, ’Pushing the Extended-Reach Envelope at Sakhalin: An Operator's Experience Drilling a Record-Reach Well,’ by Michael W. Walker, SPE, ExxonMobil, prepared for the 2012 SPE/IADC Drilling Conference and Exhibition, San Diego, California, 6-8 March. The paper has not been peer reviewed.

Extended-reach drilling (ERD) has become a common means to access reserves economically from existing infrastructure, provide access to reserves that were previously out of reach, and reduce the environmental footprint of drilling and production facilities. ExxonMobil, as operator for the Sakhalin 1 project, recently completed drilling operations at the Odoptu field, located offshore Sakhalin Island, Russia. The Odoptu development drilled nine extended-reach wells from shore, culminating with the world-record-reach OP-11. This record-setting extended-reach well reached a total depth of 12 345-m measured depth (MD) (40,502 ft) and 1784-m true vertical depth (TVD), with 11 479 m of vertical section in 60 days with less than 1% nonproductive time.

Introduction

The Sakhalin 1 project comprises the Chayvo, Odoptu, and Arkutun Dagi fields, located off the east coast of Sakhalin Island, Russia (Fig. 1).

As of January 2011, 15 of the 20 longest-reach wells in the world had been drilled in the Sakhalin 1 project, with the Odoptu Well OP-11 surpassing the 2008 Maersk Well BD-04A in Qatar.

Because of limited exploration-drilling data from the Odoptu field, the development was designed to be performed in stages. The first stage of development was designed to ascertain drilling and production performance, thereby allowing future development operations to be optimized. Hence, the project included drilling a vertical disposal well and seven ERD wells, with two additional ERD wells added subsequently.

Following the drilling of a vertical cuttings-reinjection well, the first two ERD wells at Odoptu were designed to ascertain the height of the oil column, thereby refining the remaining drilling objectives. The first well, Well OP-8, drilled an 8½-in. pilot hole that penetrated the reservoir section horizontally in the oil column and was geosteered updip to locate the gas/oil contact, measure reservoir pressures (and determine fluid gradients), and exit the top of the reservoir again at a 99° inclination. The pilot hole was then plugged, and a horizontal production hole was drilled and completed. The second well, Well OP-7, was drilled downdip to determine the pressure and fluid gradient in the aquifer leg of the reservoir. It was subsequently sidetracked horizontally through the oil column and placed into production. Using the pressure and fluid-contact data from these two wells, the height of the oil column was deter-mined and vertical placement of subsequent wells in the reservoir sections was highgraded.
Cemented-Liner- vs. Openhole-Packer- Completed Tight Gas Horizontal Wells
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 152185, ’A Direct Comparison of Hydraulic-Fracture Geometry and Well Performance Between Cemented-Liner- and Openhole-Packer-Completed Horizontal Wells in a Tight Gas Reservoir,’ by Murray Reynolds, SPE, Susan Thomson, and Faezeh Peyman, SPE, TAQA North Ltd., and Allan Hung, David Quirk, SPE, and Shaoyuan Chen, Trican Well Service, prepared for the 2012 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, 6-8 February. The paper has not been peer reviewed.

With the introduction of multiple-fractured horizontal-well(MFHW) technologies and with a much better definition of the geology, a large unconventional-resource play has developed in the Glauconitic formation in central Alberta, Canada, which could contain in excess of 5 Tcf of gas in place plus associated natural-gas liquid. Microseismic technology was used in a pilot project that was designed to test the completion effectiveness of a cased-and-cemented liner vs. an openhole-packer system in this tight gas reservoir.

Introduction

Several operators are developing this liquid-rich tight gas play by use of MFHW technologies. While most of the horizontal wells used openhole-packer systems with ball-and-sleeve fracture-isolation technology, the completion effectiveness of this technique was uncertain in this formation. A large vertical-well population within the area presented an opportunity to use downhole-microseismic techniques for direct measurement of the hydraulic-fracture growth from two offset horizontal wells. Two vertical microseismic-observation wells were located between two proposed horizontal wells, with a mid-point-separation distance of approximately 600 m. Each horizontal well would have approximately 1200-m horizontal exposure in the reservoir and would be completed with eight large hydraulic-fracture treatments (approximate fracture spacing of 170 m along the horizontal well). One horizontal well would be equipped with the open-hole ball-and-sleeve completion system, while the other would be equipped with a fully cemented liner in the horizontal section. The latter well would use ported collars at the points of fracture origination, and these would be shifted open by use of coiled tubing.

Background

Depths in the Westerose area are approximately 1840 m, increasing to 3450 m in the Deanne field. The pore-pressure gradient varies with location and depth, from slightly under-pressured in the northeast (8.5 kPa/m) to significantly overpressured in the southwest (16.1 kPa/m). Total gross zone thickness varies between 15 and 25 m, with porosities ranging from 6 to 15%. The water saturation is believed to be sub-irreducible, ranging from 25 to 30%, and no significant formation water is produced anywhere in the trend. This project has a series of regional coals that cap the Glauconitic sands. The coals vary in thickness from approximately 0.5 to 5 m, are areally extensive, and are good markers for geological mapping and correlations.
Reservoir Testing System Evolves to Meet New Frontier Challenges
Authors: Gramcko Contreras Antonio Jose
Published: February 2015

Technology Update

As today’s deep wells challenge the bounds of pressure and temperature, accurate reservoir testing has become essential to mitigate production risk. The information contained in a series of downhole pressure transient measurements and representative reservoir fluid samples can make or break a prospect’s potential.

The consistent and accurate acquisition of this information requires the precision instrumentation and functionality of a drillstem testing system. Whereas excellent downhole logging instruments can describe the near-borehole regions, only a drillstem test can reach deeply into the reservoir to discover boundaries, faults, and fractures; confirm volumetric reserves estimations; and acquire the cleanest, most representative fluid samples to provide accurate fluid phase behavior, physical properties, and com-positional analyses.

Safety, Reliability, and Efficiency

The Schlumberger Quartet high-performance downhole reservoir testing system combines four proven downhole technologies into a package that can isolate the zone, control flow, measure pressure and temperature, and acquire multiple single-phase reservoir fluid samples on a single trip into the well. The system provides enhanced safety, increased efficiency, and improved reliability to testing operations.

Compared with conventional downhole test strings, the system functions with a 35% lower tool operating pressure, 50% fewer seals, and 60% fewer connections, while requiring 90% less nitrogen. The system is four times shorter than a conventional tool string because it eliminates the requirement for a safety joint, jar, slip joints, and drill collars.

Despite its smaller size, the system is sufficiently durable to permit perforating guns to be run below the packer and fired without incurring damage to the tools or impairing their accuracy or integrity. The system also includes a below-packer circulating valve to allow a more efficient well kill following the test, which is especially important when testing gas wells.

Each of the four tools that make up the downhole reservoir testing system operates individually and collectively to perform the test. The CERTIS high-integrity reservoir test isolation system delivers production-quality well isolation. The isolation system combines the features of a retrievable drillstem test packer with a hydraulically set permanent packer, making the safety joint, jar, slip joints, and drill collars unnecessary. Because the system is actuated by annulus pressure, no rotational or set down forces are required.
Doing More With Data
Authors: Rassenfoss Stephen
Published: February 2015

Handling Big Data, Getting Together in a Cloud, Real-Time Quality Control

A few years ago, Mario Ruscev was in charge of a project to wire an oil field with a state-of-the-art system giving operators multiple streams of production data from each of the wells in the field. When it was all done and time to turn it over, the field’s manager surprised him by asking: “What do we do with it?” said Ruscev, now chief technology officer at Baker Hughes.

That field was on the leading edge of a flood of fields since then that have installed sensors to constantly measure what goes on while drilling wells and producing oil, and the industry is working on answering Ruscev’s question.

“We are in a catch-up phase. It takes some time to make sense of these new sets of data, before we figure how to really use it and how to relate it to what we want to do,” Ruscev said. Without good applications for using it in decision making, “data is just data.”

This cycle is likely to follow the same path as seismic, where advances, such as the advent of 3D seismic acquisition, enormously increased the volume of data gathered. “There have been two revolutions in seismic and we’ve never been stopped by it,” Ruscev said. “It just took time to be able to produce good results from these data.”

Fast-rising computing processing power will be able to digest the big data coming in, but he said the hard part in seismic, and now in reservoir and drilling, is relating those measurements in useful ways to “what is happening to the formation.”

Ruscev told his story during a panel discussion at the SPE Digital Energy Conference and Exhibition, in March in The Woodlands, Texas, which was filled with people working on better things to do with information. The initiatives range from mining data in well logs to make better maps showing underground stresses to doing quality control checks on data as it flows in.

Much of it is built on algorithms written to apply advanced numerical analysis methods seeking insights in the numbers.

One of the exhibitors was Sekal, a fast-growing, young company that uses real-time data analysis of measurements, such as the weight of the drillstring and the downhole pressure. The point of the work is to detect small changes in drilling conditions that could lead hours later to a big problem that could halt work, said Bill Chmela, a vice president at Sekal.
Liwan Gas Project: South China Sea Deepwater Case Study
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 16722, ’The Liwan Gas Project: A Case Study of a South China Sea Deepwater Drilling Campaign,’ by David Triolo, SPE, and Tracy Mosness, SPE, Husky Energy, and Rana Khalid Habib, Schlumberger, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.

The Liwan gas reservoir was discovered in the South China Sea Block 29/26 in September 2006. A sixth-generation, deepwater semisubmersible platform was contracted that subsequently drilled 26 deepwater wells (700- to 1600-m water depth) between November 2008 and November 2011. During the 1,011 days of drilling and testing activity, the rig and onshore supporting teams incurred no lost-time incidents. The rig team drilled 61 593 m of hole below the mudline and ran the associated strings of casing. Nonproductive time consumed 265 days (26.6 %), comprising 65 days waiting on weather, 147 days of rig repair, and 53 days of other unscheduled events.

Introduction

In April 2006, a dynamically positioned drillship drilled exploration Well Liwan 3-1-1 in 1500 m of water to a depth of 3843 m, discovering the Liwan 3-1 sand-stone, a gas-bearing reservoir. The Liwan 3-1 field is approximately 320 km south-east of Hong Kong in 1300- to 1500-m water depth, as shown in Fig. 1. The nearest field was 64 km northwest. The main reservoir in the Liwan 3-1 gas field (Sand 1) is the Zhujiang formation.

Weather and Ocean Environments. The South China Sea presents significant weather conditions that affect offshore operations. Tropical cyclones, typhoons in the western Pacific, occur throughout the year over the northern South China Sea. China’s offshore operators evacuate personnel from permanent and moored offshore facilities when typhoons approach. For dynamically positioned drilling rigs, the typhoon is monitored as it forms and a judgment is made as to when to suspend operations. While drilling, the average time required to suspend operations and recover the lower-marine-riser package (LMRP) or blow-out preventer (BOP) is approximately 72 hours. Nonessential crew are evacuated, and the rig moves out of the path of the typhoon, generally in a southwest direction. There are two monsoons that affect the South China Sea: Northeast (between November and March) and Southwest (between May and September) monsoons, the nomenclature deriving from the predominant wind direction.
Cemented-Multistage-Sleeve Completion Improves Efficiency of Fracture Stimulation
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 163842, ’Cemented Multistage Sleeve Completion Improves Efficiency of Fracture Stimulation in an Eagle Ford Shale Well,’ Glenn Adcock, Sanchez Oil and Gas, and Ben Wellhoefer, SPE, Said Daher, and Eric Fruge, Halliburton, prepared for the 2013 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, 4-6 February. The paper has not been peer reviewed.

The Eagle Ford shale in Zavala County, Texas, is similar to many high-carbonate-content oil-shale formations. As with other shale plays, the industry has preferred using cemented lateral sections as the primary means of fracture-stage isolation, coupled with the plug-and-perforate (PAP) horizontal-completion technique. An alternative completion method, cemented multistage sleeves (CMSSs), recently improved efficiency and reduced completion cycle time. The 16-stage stimulation operation was completed in 24 hours with continuous pumping compared with an average of 3 days for PAP.

Introduction

This paper highlights the key well (Fig. 1) that successfully implemented the new CMSS completion technique. The key well has been compared to averages from wells using the PAP technique to illustrate how the CMSS technique was able to achieve the completion goals while dramatically increasing completion efficiency. The subject well was drilled to a measured depth (MD) of 11,965 ft, with a lateral length greater than 5,913 ft, and was completed using 16 stages of CMSS technology to fracture stimulate the entire lateral section, which was placed in the Eagle Ford shale. The CMSS technology allowed for 3.80 million lbm of proppant to be placed with 2,901,000 gal of fluid to fracture stimulate the wellbore at an average rate of 54 bbl/min. The 15 stages of stimulation were completed in just 24 hours with continuous pumping operations, compared with an estimated 3 days for a PAP completion and 5 days for previous wells in Fayette County, Texas.

Challenge

A major challenge in unconventional reservoirs is developing more-efficient integrated completion methods to improve well economics and lower the cost per barrel of oil equivalent (BOE).

Wellbores previously completed with the PAP technique in Fayette County took an average of 5 days. These wells contained 15–20 fracture stages using a fracture design similar to that of the subject well. The challenge of reducing the completion cycle time was seen as an opportunity to improve efficiency and well economics. However, production must not be sacrificed. CMSS completion was used to evaluate whether the technique could achieve both goals.
E&P Notes (May 2014)
Authors: Rassenfoss Stephen
Published: February 2015

E&P Notes

Fracturing by the Numbers: A Complex Balance

For those in shale exploration, “fracability” is a real word, a critical property, and a point of contention.

Fracability has entered the vocabulary of exploration because it is critical for exploration to know if rocks will produce when hydraulic force is applied. It can be a divisive concept, in part because there are a lot of ways to determine fracability, with dueling test methods and multiple equations offered by experts in petrophysics and geomechanics.

A Lighter UltraStrong Proppant

Oxane Materials has joined the 20,000 club—joining the two makers who have announced they are selling proppant capable of standing up to high pressures.

The new offering, called OxThor, meets the standard set for use in frontier fields, such as those in the Lower Tertiary trend in the US Gulf of Mexico, where the grain-sized spheres will be called on to prop open fractures in wells drilled in ultradeep water that are around 30,000 ft deep.

Carbon Dioxide Reserves Could Alter US EOR Map

Growth in enhanced oil recovery (EOR) projects using carbon dioxide (CO2) in west Texas could be limited by supplies unless new sources of the gas are found in the ground or from industrial facilities.

A recent report from the US Department of Energy (DOE) said that CO2 fields currently supplying west Texas, which has the largest concentration of EOR projects using carbon dioxide, can continue to produce at current levels for 10 to 20 years. That might be a constraint in an area where the number of potential projects could significantly increase demand.

Colorado Emissions Control Rule Offers Some Flexibility

Colorado will become a testing ground for reducing emissions from oil and gas exploration and production (E&P). A new rule, known as Regulation 7, is an early effort at reducing E&P emissions and may help resolve a contentious issue in a state that combines rich unconventional oil and gas resources and significant opposition to how they are developed.

The addition of another regulation is not likely to be celebrated in the industry, but the collaborative process used to write the rule was praised by the head of one of the affected companies. “Hopefully, it is a new way to write a regulation,” said Doug Suttles, CEO of Encana, during his keynote address at the start of the IADC/SPE Drilling Conference and Exhibition in Fort Worth, Texas.
Big Barriers to Building a New Generation of Arctic Vessels
Authors: Jacobs Trent
Published: February 2015

The industry’s experience thus far drilling offshore the Arctic is a powerful argument to build a new generation of vessels and drilling rigs purpose built for operations in heavy ice. Many of the new exploration concepts that seek to overcome challenges in the Arctic were presented at the recent 2014 Arctic Offshore Technology Conference in Houston. Alexander Brovkin, a facilities and logistics adviser at the Chevron Arctic Center, agrees that while new vessel technology is needed for exploration drilling in the Arctic, first the resource must be proved by the drill bit. “An operator must first have a portfolio of Arctic wells before making a significant capital investment to design or build something new,” he said, adding that companies will be pushed to make decisions soon in order to comply with the terms and deadlines set by their offshore leases.

Following Shell’s recent experiences, Arctic exploration off North America is at the moment paralyzed. Considered to be two of the most promising Arctic areas, development in the Chukchi and Beaufort Seas offshore Alaska has stalled out despite there being dozens of leases in those areas set to expire over the next couple of years.

And after spending billions of dollars on its Arctic drilling program to date, Shell canceled all operations in the area for this year. The decision followed a series of accidents during the company’s Alaskan expeditions that began 2 years ago, one of which involved a drillship running aground, and a United States federal court decision that created uncertainty over the terms of its leases. ConocoPhillips and Statoil followed suit and have indefinitely postponed their Arctic drilling plans off Alaska. However, in the Russian Arctic, ExxonMobil and Rosneft are pressing ahead with a joint venture using conventional semisubmersible technology, which limits their operations to the open water season.
New-Generation Drillpipes Enhance Extended-Reach Drilling in South China Sea
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16798, ’New Generation of Aluminum Drillpipes Enhanced ERD Performances in the Huizhou Field, South China Sea,’ by W. Scaruffi, E. Cristofanelli, S. Yu, and A. Trocchia, Eni China, and C. Molaschi and A. Merlo, Eni, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. Copyright 2013 International Petroleum Technology Conference. Reproduced by permission.

This paper presents the results of a performance-improvement effort in extended-reach drilling (ERD) in three campaigns in the Huizhou HZ 25-4 oil field in the South China Sea. The new methodological approach and the deployment of new-generation aluminum drillpipes (ADPs) have resulted in a reduction of drilling risk and increased cost savings.

Introduction

ERD allows the reduction of the number of drilling sites, including offshore platforms, artificial islands, or other structures, and allows better control of total field-development costs. In addition, ERD technology makes it possible to reach reservoirs located at a considerable distance offshore, reducing the environmental impact of a wellsite. ERD operations are gaining momentum in the industry because they allow reserves exploitation previously considered too expensive when using conventional drilling methods. In addition, ERD techniques increase singlewell production by enlarging the drainage area. Because of their lighter weight when compared with steel drillpipes (SDPs), the use of ADP is a key solution for drilling extended- reach wells for the following reasons:

A reduction in operating costs of approximately 10–20% (including savings in rig-capacity upgrade costs, transportation and energy costs, time-hosting costs, and tool-joint/casing-wear costs).

An increase in the horizontal deviation of wells of approximately 10–30% (reduced torque-and-drag effect, less pressure drop, higher buckling resistance).

Heightened reserves and production growth.

A reduction in operative risk.

Comparison of ADPs and SDPs

Eni E&P first considered ADPs in July 2003, during the proposal and approval of a research-and-development project.
Marginal Field Achieves Major Success In Thailand
Authors: Moon Ted
Published: February 2015

For any project, proper planning is critical to successful execution. This fact is exemplified in the planning and execution of the Bualuang field in the Gulf of Thailand, which went from the idea stage to drilling its first wells in a span of 18 months during an extremely competitive construction period for the offshore oil and gas sector.

The Bualuang oil field was discovered by London-based E&P company Soco International in 1992 in 197 ft (60 m) of water in Block B8/38 in the Gulf of Thailand. It was estimated to hold reserves of 15–20 million BOE—classifying it as a marginal field. Salamander Energy is the operator and holds a 60% interest in the field, with Soco holding the remaining 40%.

In mid-2006, the Thailand Department of Minerals Fuels gave Greenfield International Oil and Gas (GFI) (purchased by Salamander in 2008) the green light to develop the field. With only an 18-month window of finance availability afforded for the project, the company knew it had to move quickly to complete construction and installation.

A conceptual study conducted in third quarter of 2006 settled on a field design consisting of five subsea producing wells; one water injector; an unmanned wellhead platform (WHP); and a floating production, storage, and offloading (FPSO) vessel. To connect the WHP with the FPSO, subsea infrastructure was planned, which consisted of two 10-in. pipelines, a 4-in. power umbilical, two flexible risers and umbilical, a mooring hawser, and a gravity-base pipeline-end manifold (PLEM).

The decision to use a WHP arose partly from the familiarity of this type of design in the region, which would usually allow for a relatively short design and development window. “Due to the typical decline curves from producing wells in the Gulf of Thailand, a large number of facilities are required to support new wells each year,” said Rodney Silberstein, engineering and project director with ARV Offshore, a Thailand-based field-development and project-, engineering-, and construction-management firm that oversaw the field development at Bualuang.  “As a result, there are more than 300 WHPs in the Gulf of Thailand operating in 60–80 m of water depth, giving us a significant historical reference base for the design and construction details on Bualuang.”
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>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.