bluuebunny/crossref_metadata_2025_split huggingface dataset:
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 The paper has not been peer reviewed.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.”