bluuebunny/crossref_metadata_2025_split huggingface dataset:
Can Geoscientists Resolve the CCS Paradox?
Authors: Torp Tore A. 
Published: February 2015

R&D Grand Challenges - This is the fourth in a series of articles on the great challenges facing the oil and gas industry as outlined by the SPE Research and Development (R&D) Committee. The R&D challenges comprise broad upstream business needs: increasing recovery factors, in-situ molecular manipulation, carbon capture and sequestration, produced water management, higher resolution subsurface imaging of hydrocarbons, and the environment. The articles in this series examine each of these challenges in depth. The R&D Grand Challenges Series, comprising articles published in JPT during 2011 and 2012, is available as a collection on OnePetro (SPE-163061-JPT).
International energy and climate organizations have found carbon capture and storage (CCS) to be a promising technology to resolve the squeeze between fast-growing global energy needs and global warming. Even environmental organizations say that making our energy use more efficient and building enough new renewable energy capacity takes too long. We need to get the CCS working to curb the growing greenhouse gas emissions if too large a climate change is to be avoided.
CCS consists of three major interdependent steps:
Capture the carbon, CO2 out of flue gases, either from the stack of a power plant or the blast furnace top gas in iron making.
Transport it by pipeline or ship it underground.
Safely keep it in a storage site for thousands of years.
The technology for each of these steps has been used for decades in the industry, mostly in oil and gas. The important change is the scale—from about 100,000 to 1 million metric tons per year in the past. Today, we see the need for handling 10 million tons in each installation and for perhaps several thousand installations. The amount of CO2 produced from one power station varies from 2 million to 10 million tons; a modern iron-making blast furnace emits up to 10 million tons per year. The costs of the technologies for a large-scale CO2 handling chain are estimated to be split roughly 75%-10%-15% for capture-transport-storage.
West of Shetland Development Gathers Momentum
Authors: Sheehan John 
Published: February 2015

BP is ramping up its West of Shetland operations with the UK government approval to push ahead with the second phase of its giant Clair field development, Clair Ridge. Plans to redevelop the Schiehallion and Loyal fields with a new floating production, storage, and offloading vessel (FPSO) are also gathering pace.
The Clair reservoir is the largest known hydrocarbon resource on the UK Continental Shelf (UKCS), occupying an area of 220 sq km. It is located approximately 75 km west of the Shetland Isles in 459 ft of water. Because of its size and complexity, it is being developed in phases.
Clair Ridge, in UKCS Block 206/8, lies to the northeast of Clair Phase 1 and will be tapped with a pair of bridge-linked platforms—a drilling and production (DP) facilities platform and an accommodation and utilities (QU) platform. The new platforms have a 40-year design life and will require a total capital investment of about GBP 4.5 billion (USD 7.16 billion).
The topsides for the two platforms are being built in modular form by Hyundai Heavy Industries in South Korea and will be transported to the Clair Ridge field on five Dockwise heavylift vessels. Kvaerner Verdal in Norway is building the platform jackets. The DP jacket will have a total weight of 22,300 tonnes and the QU jacket will weigh 9,000 tonnes.
Peter Brawley, the Clair Ridge hook-up and export systems manager, said the sheer scale of the project is a challenge in itself. “This is a huge platform we are building. The biggest platform we operate on the UKCS at the moment is Magnus at 34,000 tonnes and here, we have topsides of 40,000 tonnes. It is bigger than anything we have built in the UKCS, so the scale is a challenge,” he said.
“On the QU platform we have one large 10,000 tonne module, which comprises the bulk of it. On top, we have a power generation module and on the side, we have the accommodation module. We will have three lifts on QU.
“On DP, we have the DP East module, the DP West module, each of which is around 10,000 tonnes. Then we have the compression module that goes on top of DP East and then we have the drilling support module and the drill rig itself. The final two modules are the flare boom and the bridge,” he said.
The facilities will have a maximum processing capacity of 120,000 BOPD, which will flow to the Clair Phase 1 pipeline through a new oil export pipeline and onward to the Sullom Voe Terminal. The DP platform will also be tied into the West of Shetland Pipeline System through a carbon steel gas export pipeline.
Technology Focus: Reserves/Asset Management (December 2011)
Authors: Hinkle Delores 
Published: February 2015

Technology Focus
As a member of the JPT Editorial Committee, I am privileged to review papers presented at SPE events during the last year in the area of Reserves and Asset Management. I am always impressed by the highly skilled, innovative members of our Society who address the constant change in our industry in these papers.
Recently, many of the reserves papers have focused on changes in reserves and resource estimation resulting from the introduction of the Petroleum Resource Management System (PRMS) and the US Securities and Exchange Commission’s (SEC’s) Modernized Rules. Last year, many of the papers dealt with theoretical aspects of reserves estimation in unconventional plays. This year, most of the papers dealt with unconventional reserves, focusing on integration of theoretical and practical aspects of the engineering principles used to estimate reserves and resources. Several papers went full circle to address how issues around PRMS or the SEC’s Modernized Rules affect reserves and resource estimation in unconventional resources.
There was a similar shift in asset-management papers. Prior years were weighted heavily toward theoretical-optimization approaches, primarily focused on surface facilities. This year, there were many excellent papers addressing the practical application of those principles in technically challenging, high-cost environments. Integration of surface and subsurface components to improve efficiency was another recurring theme.
The fact that I could select only a few of the many outstanding papers that I reviewed highlights the importance of attending the venues at which these papers are presented. The insight provided during the presentation’s opportunity to ask questions yields valuable information that cannot be obtained by reading the paper alone. I selected the papers for highlighting and those recommended for additional reading with a view to the needs and interests of the membership of our global society. I hope I found something that will benefit each of you.
Reserves/Asset Management additional reading available at OnePetro: www.onepetro.org
SPE 128542 • “Greater Plutonio—Real-Time Reservoir Management in a High-Cost Deepwater Environment” by Dave Booth, SPE, BP plc, et al. (See JPT, September 2010, page 43.)
SPE 147623 • “Estimated Ultimate Recovery as a Function of Production Practices in the Haynesville Shale” by V. Okouma, Shell Canada Energy, et al.
SPE 142822 • “Tight Gas Modeling Frameworks for Improved Reservoir Management and Application to the Moxa Development Area” by Felipe Gallego, BP plc.
SPE 146788 • “Field-Development Optimization Under Uncertainty: Screening Models for Decision Making” by B.A. Ogunyomi, SPE, University of Texas at Austin, et al.
Production Acceleration or Additional Recovery? A Look Back at Three Published Field Trials - Long-Term Benefits of Improved Fracture Treatments
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 144349, ’Production Acceleration or Additional Recovery? A Look Back at Three Published Field Trials To Determine the Long-Term Benefits of Improved Fracture Treatments,’ by K. Blackwood, SPE, Highmount Energy; P. Handren, SPE, Denbury Resources; and M. Chapman, SPE, T. Palisch, SPE, and J. Godwin, SPE, Carbo Ceramics, prepared for the 2011 SPE North American Unconventional Gas Conference & Exhibition, The Woodlands, Texas, 14-16 June. The paper has not been peer reviewed.
Improved fracture-treatment designs can increase production rates from many reservoirs. However, do these changes merely accelerate recovery, or is incremental production gained by changing the fracture design? The authors re-examined three tight gas case studies published in the past 10 years. The original studies were performed specifically to assess the effects of increased fracture conductivity on production. In all cases, the initial analyses documented that increasing conductivity appeared to increase production and recovery.
Introduction
Since the first commercial hydraulic-fracture treatments in 1949, treatment designs have evolved from experimentation with massive hydraulic fractures to proppantless water-fracture treatments. While the production increase in the first few months or even the first year typically repays the cost of the conductivity upgrade, and is robust enough to make the decision to upgrade relatively simple, it is important to know whether this increase can be translated into additional ultimate recovery. If the ultimate recovery is also increased, then the economics of the completion upgrade may be even more favorable because it leads to a potential increase in reserves and drainage area per well, which in turn can lead to a reduction in the number of wells needed to drain the reservoir effectively.
In all cases, comparisons were made between high-quality ceramic proppants and either uncoated or resin-coated sand (RCS). In the past, conventional wisdom incorrectly suggested that hydraulic fractures in most tight gas wells behaved as “infinitely conductive.” This misperception arose from a poor understanding of proppant performance under downhole (realistic) conditions. Under realistic conditions, all proppants should be expected to lose more than 90% of their effective conductivity. By reanalyzing these case studies with longer term production results, the authors sought to determine whether the original conclusions still hold true, and whether confidence in the recovery projections can be determined.
Drilling Automation: An Automatic Trajectory-Control System
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 143899, ’Drilling Automation: An Automatic Trajectory- Control System,’ by Dimitrios Pirovolou, SPE, Clinton D. Chapman, SPE, Minh Chau, Hector Arismendi, Mbaga Ahorukomeye, and Juan Penaranda, Schlumberger, prepared for the 2011 SPE Digital Energy Conference and Exhibition, The Woodlands, Texas, 19-21 April. The paper has not been peer reviewed.
Rotary steerable systems (RSSs) enable faster drilling, smoother wellbores, and extended-reach drilling. Still, a drilling assembly built around an RSS tool is sensitive to factors such as bit type, operating parameters, type of drilling fluid, lithology, and borehole diameter. Therefore, it is not always optimal for a human operator [typically a directional driller (DD)] to select and issue the correct commands to the drilling tool at the correct time. This situation becomes even more challenging when those decisions must be made in a matter of minutes.
Introduction
Typically, the DD monitors the path of a wellbore by use of stationary surveys, which include measured depth, inclination, and azimuth at the downhole survey station and the three computed Cartesian coordinates: true vertical depth (TVD), north/south (N/S), and east/west (E/W). Also, the DD sometimes uses continuous surveys (i.e., while-drilling vs. static surveys) to monitor the steering behavior of the drilling tools qualitatively. All this information is used to estimate the actual trajectory being drilled.
An RSS generally works by pointing or pushing the bit in a particular direction with a specified amount of force. The direction and force are set by issuing steering commands from the surface to the RSS tool. By downlinking steering commands while the well is being drilled, well paths can be created that follow a specific predefined plan. However, the steerability of the system can be affected by operating parameters such as weight on bit, rotary speed, and hardness of the formation being drilled.
In remote operations, when a DD may be monitoring or executing more than one job, the expertise generally must increase as the time constraints tighten. This requirement further necessitated tools that could assist the DD to maintain the desired plan.
Steering Application
Use of directional information enables correlating a drilled path to the RSS commands that were issued to drill the wellbore. Measurements can be from either a static or a continuous (while-drilling) survey. The problem has two main components and is diagrammed in Fig. 1.
Understanding the steering behavior of the drilling tool on the basis of steering commands (input) and actual steering responses (output)—Blocks 1 and 2 of Fig. 1.
Suggesting the optimal steering command to send to the RSS tool that will produce the desired steering response—Blocks 3 through 5 of Fig. 1.
Generating Electricity From Produced Water
Authors: Dahlheim Robin , Pike William J. 
Published: February 2015

Technology Update
There are 823,000 oil and gas wells in the United States that coproduce hot water with their hydrocarbon output. This equates to approximately 25 billion bbl of water annually that could be used as fuel to produce up to 3 GW of clean electrical power. Not only would electricity generated from produced water add much needed electrical power, the life of many of these wells also would be extended and additional oil and gas produced.
A recent project funded by the National Energy Technology Laboratory of the United States Department of Energy conducted field demonstrations to determine the potential of generating electricity from hot produced water. Participants included Gulf Coast Green Energy (GCGE), ElectraTherm, Den-bury Resources, the Southern Methodist University (SMU) Geothermal Laboratory, the Texas A&M University petroleum engineering department, and Dixie Electric Cooperative.
The primary goal of the project was to prove the feasibility of interfacing the ElectraTherm Green Machine, a waste heat-to-power generator, with a producing oil or gas well. The project’s subsidiary goals were as follows:
Demonstrate the ability to produce electricity from waste heat in the produced water.
Show that producing electricity from produced water does not interfere with normal well operations.
Demonstrate how small oil and gas producers might increase their profitability by adding an income stream from power generation.
Determine the economic viability of generating electricity from waste heat in the produced water.
Determine whether the kWh output of electricity from the produced water has practical applications.
Identify the environmental impact of generating fuel-free, emission-free electricity from waste heat in the produced water.
It was important to hold a field trial to determine the extent of known factors that could not be identified or quantified in laboratory and bench scale runs. In addition, a field trial was necessary to identify potential corrective measures for new equipment designs and future produced water projects. The site chosen was a producing oil well, Denbury’s Summerland No. 2 well, near Laurel, Mississippi. In production for 5 years, the well has a high water cut and high produced water temperature. The well produces 100 BOPD and 4,000 BWPD from a depth of 9,500 ft with an electric submersible pump. The temperature of the produced water exiting the “knockout” tank at 120 gal/min is 204°F. The site has an ambient temperature range of 60°F to 105°F.
Mapping the Way to Optimized Production in Shale Formations
Authors: Neville Tom , Donald Adam 
Published: February 2015

Technology Update
A two-step analysis can provide the key information needed to design optimal shale completions. The first step is to evaluate reservoir quality, which describes the hydrocarbon potential of a shale. The second step is to evaluate completion quality, which describes stimulation potential. Core analysis provides the basis to help calibrate the results of these two steps. The intersection of good reservoir quality and good completion quality leads to the best chance for success in shale completion. However, a failure to address both reservoir quality and completion quality will jeopardize the achievement of the ultimate goal: optimized production.
A shale reservoir by definition is a hydrocarbon source, reservoir, trap, and seal in a single package. Though similar in outward appearance, no two shales are alike. They are typically complex, heterogeneous rocks with extremely low permeability. Stress anisotropy is commonplace. This calls for the judicious integration of geology, petrophysics, geomechanics, and reservoir engineering to solve the puzzle that will enable the reservoir to yield its prize.
Reservoir Quality
To determine reservoir quality, defined as the hydrocarbon potential of a shale, it is necessary to quantify the amount of hydrocarbon in place and its deliverability to the fracture face. To do this, we must know the organic matter content and type, its thermal maturity, the effective porosity, fluid saturations, matrix permeability, and reservoir pressure.
The hydrocarbon in shale has evolved from thermogenic or biogenic alteration of kerogen, a fossilized organic material that is the source of oil and gas. In addition to providing the hydrocarbon source, kerogen plays a key role in developing reservoir quality in shales. Its degeneration creates pore space that makes up in part for the porosity lost during sedimentary compaction.
Because of its extremely high surface area and affinity for hydrocarbon molecules, this pore space is an excellent storage medium for gas, which becomes adsorbed onto the organic surfaces. In addition, free gas or oil may exist in larger pores, both within kerogen and between mineral grains. Understanding the mix between adsorbed and free hydrocarbons is essential for calculating total hydrocarbon content. Because of the role of kerogen in creating pore space and providing hydrocarbon storage, there is a strong correlation between kerogen content and total porosity, hydrocarbon saturation, and permeability. Therefore, kerogen content, or total organic carbon content (TOC), is an important indicator of overall reservoir quality.
Technology Focus: Reserves/Asset Management (December 2012)
Authors: Hinkle Delores 
Published: February 2015

Technology Focus
While preparing for this month’s feature on reserves and asset management, I had the privilege of reviewing more than 100 abstracts from papers presented on the topic over the past year at SPE workshops and conferences. Interestingly, more than 10% of those abstracts addressed risk in some fashion. Integration was another common topic. Finally, I was a bit surprised by the number of abstracts that contained the word “practical” in their title. It struck me as a challenge we all face as part of our daily activities—integrating risk in a practical way.
The subject matter of the reserves papers I reviewed was widely varied but extremely useful. Papers addressed practical application of engineering processes to comply with the Securities and Exchange Commission’s 2009 modernized rules, innovative reserves forecasting approaches for unconventional reservoirs, the integration of geostatistics and reservoir modeling in reserves estimation, case studies where reserves were both under- and overestimated, and a variety of other topics.
As a topic, asset management also covers a wide range of issues. Papers continued to offer insight into field development optimization, techniques to manage risk, application of project management systems, innovative integrated asset models, and related topics. All of these papers provide in-depth, innovative analysis of issues resulting from the constant growth and development of our industry.
Choosing only four papers to be highlighted was a challenge. There were many, many quality papers covering current topics of interest. I tried to select papers that span the interests of the global industry and hit a balance between practical and theoretical information. The papers I selected for additional reading represent interesting case studies of somewhat innovative reserves estimation approaches. I hope you find both the highlighted papers and those for additional reading as interesting and thought provoking as I did.
Finally, anyone interested in more in-depth information on either reserves or asset management will find a wealth of additional information at www.jptonline.org, where the full-length papers of those synopsized here are available free to SPE members for 2 months. All of the papers contribute to the advancement of knowledge in our industry, and the authors who contributed to that cause by writing a paper should be congratulated.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 151045 Interference Study in Shale Plays by Ayantayo Ajani, The University of Tulsa
SPE 143843 Reserves Follow-Up Using an Integrated Deterministic/Probabilistic Approach by Hugo Araujo, Repsol-YPF, et al.
SPE 142936 Integrated Asset Model in Camisea, Peru by A. Downie, Baker Hughes, et al.
SPE 146788 Field Development Optimization Under Uncertainty: Screening Models for Decision Making by B.A. Ogunyomi, The University of Texas at Austin, et al.