bluuebunny/crossref_metadata_2025_split huggingface dataset:
Exploration Tries To Answer Questions About the Lower Silurian Longmaxi Shale in China
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper IPTC 14487, ’Sichuan Basin Shale Gas, China: Exploring the Lower Silurian Longmaxi Shale,’ by Claudia Hackbarth, SPE, Danny Soo, and Navpreet Singh, SPE, Shell, prepared for the 2011 International Petroleum Technology Conference, Bangkok, Thailand, rescheduled to 7-9 February 2012. The paper has not been peer reviewed.
Shale-gas exploration in China is already under way and rapidly increasing in activity level. The Sichuan basin, one of the most prolific petroleum basins in China, is at the forefront. However, exploration and assessment of an untested shale-gas play is typically lengthy and expensive. Compared with conventional oil and gas projects, shale-gas projects may require a number of early wells to prove the existence and distribution of the gas but then many more wells to test and optimize engineering techniques until a commercially viable combination is found. This process could be summarized into two overarching questions: “Is there a material amount of gas?” and, if yes, “Can it be produced economically?”
Sichuan Basin Structure
The topographic Sichuan basin today is a remnant of the originally much larger Upper Yangtze cratonic sedimentary basin (Fig. 1). In the southern Sichuan basin, structures are characterized by thin-skinned faulting and thrusting, often above an Upper Cambrian detachment surface, likely an evaporitic ductile layer that now cores the folds.
The Sichuan-area stratigraphic column contains several potential source-rock intervals. Industry has so far focused attention on the Lower Cambrian Qiongzhusi and the Ordovician-Silurian boundary as potential shale-gas reservoirs.
The Upper Ordovician Wufeng shale and Lower Silurian Longmaxi formation are generally regarded as belonging to the same black-shale succession, but an erosional surface and regional disconformity separate the two intervals. The Longmaxi formation is not as widespread as the Wufeng formation and is restricted to the Yangtze region. From the bottom up, the Ordovician/Silurian succession consists of
A lower graptolite-bearing, black or dark-gray, carbonaceous/siliceous shale (Wufeng formation), generally several meters thick
The Guoyinchao limestone or calcareous siltstone with abundant Hirnantian fauna and other shelly fossils, typically 0.5–3 m thick
The Lower Longmaxi black, graptolite-bearing, carbonaceous/siliceous shale with cherty slate
The Upper Longmaxi gray calcareous mudstones and siltstones, interbedded with an increasing number of thin limestone layers toward the top of the formation
Regional studies indicate that Wufeng and Longmaxi shales were buried deeply enough over a large area of the Sichuan basin to have reached the gas-generation window.
CO2 Enhanced-Oil-Recovery Project Injects New Life Into Madison Reservoir in Wyoming
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 152862, ’Beaver Creek Madison CO2 Enhanced-Oil-Recovery Project: Case History - Riverton, Wyoming,’ by Charles A. Peterson, SPE, Edward J. Pearson, SPE, and Veronica T. Chodur, SPE, Devon Energy, and Carlos Periera, M3 Petroleum Engineering, prepared for the 2012 SPE Improved Oil Recovery Symposium, Tulsa, 14-18 April. The paper has not been peer reviewed.
The Madison reservoir, located in the Beaver Creek field, 14 miles south-southeast of Riverton, Wyoming, (Fig. 1) is found at an average depth of 11,235 ft, making it among the deepest CO2 enhanced-oil-recovery (EOR) projects in the United States. The Beaver Creek Madison project is the most recent CO2 EOR project in Wyoming. With a preproject oil production of 43 million bbl, this flood is projected to increase recovery by 11.1 million bbl, or 10% of the estimated 109 million bbl of original oil in place. Early CO2-flood response has been increased production from a preflood rate of 280 BOPD to the current rate of 5,100 BOPD.
Introduction
The Beaver Creek field produces from 12 different formations, ranging from the shallow Lower Tertiary Ft. Union formation at 1,150 ft to the Mississippian Madison formation at depths down to 11,664-ft true vertical depth. To date, the field has produced in excess of 80 million bbl of oil and 800 Bcf of gas. The Madison reservoir itself produced 44.6 million bbl of oil up through the beginning of the EOR flood.
The Madison project, designed as a combination peripheral and gravity-stable CO2 EOR project, began construction in 2007, with initial CO2 injection in July 2008. Since then, production increased from 280 BOPD to more than 5,100 BOPD as of January 2012 and recovered an incremental oil volume in excess of 2.6 million bbl through the end of 2011.
Field History and Madison Development
The Beaver Creek field was discovered in June 1938 with the drilling of the Standolind (Amoco) Beaver Creek Unit (BCU) 1. The well is still active today, having produced more than 38 Bcf and still flowing at 176 Mcf/D.
In January 1954, the Madison reservoir was discovered with the drilling of Standolind’s BCU 30 to a depth of 11,447 ft. The Madison oil-production rate peaked at 8,797 BOPD in November 1962 (Fig. 2). Production remained fairly stable until 1966, when the reservoir’s oil rate began declining while water production increased. Production eventually stabilized in 1999 and remained at approximately 280 BOPD until the beginning of the CO2-flood project. Through this period, the reservoir produced a total of 44.6 million bbl of oil, 12.8 Bcf of gas, and 282.5 million bbl of water.
Comments: Farewell
Authors: Denney Dennis 
Published: February 2015

Editor's column
For the past 17-plus years, it has been my privilege to serve as your JPT Technology Editor. After growing up in the oil patch as the son of a sales engineer for a major service company, I have spent all but a couple of years of my adult life as an oily.
When I came aboard JPT, there was this idea of publishing condensed versions of SPE technical papers rather than the traditional full-length, peer-reviewed papers. The plan was to get more important technical information in front of more SPE members more quickly. That was a new type of job for me. I had spent 20 years as a petroleum engineer in reservoir and production engineering with Mesa Petroleum and Maxus Exploration (actually nearly 30 if you count my time as a well tester for Diamond Shamrock—thank you, Bud Reitman, for encouraging me to go back to school to get my PE degree).
The first full year of publishing these synopses (1997), we covered 22 separate topics (coiled tubing, cementing, production operations, etc.) This year, JPT will publish synopses under 46 topics. With the help of Karen Bybee, who retired 2 years ago, and now Adam Wilson, almost 2,500 papers have been presented to you in the pages of JPT. As an SPE member before I began working at JPT, I remember how difficult it was to find and read papers of interest—most of all, there was the lack of time to read full-length papers trying to find information that I could use in my job.
Now, these shortened papers present enough material for busy engineers to determine if the technologies and case studies described are of value. I especially hope that engineers read papers from disciplines other than their primary ones. I am not an educator (I tried it) but my goal at JPT always has been to spread knowledge among SPE members. And it was always my hope that these synopses would pique the interest of readers, allowing them to see the range of possibilities a technology presents and imagine new applications to challenges they were facing.
When taking junior- and senior-level courses in college, we used SPE papers as much as, if not more than, textbooks to learn engineering technology and applications. Since going to work for you here at SPE, I have learned that you can use SPE papers to expand your knowledge exponentially. A great advantage of SPE is access to the breadth of technology available in the papers, from the simplest applications to the most highly technical. Almost every engineering discipline is represented here. Besides petroleum technology, information in the construction, marine, civil, structural, safety, mechanical, electrical, and other sectors is represented.
2013 OTC Mirrors Current Industry Vitality
Authors: Parshall Joel 
Published: February 2015

Conference Review
This year’s Offshore Technology Conference (OTC), held 6-9 May in Houston, reflected the offshore oil sector’s health and energy, with attendance hitting a 30-year high and the event attracting top industry names from around the world. The globe’s largest offshore industry event attracted 104,800 people, the second highest in show history and up 17% from last year. Exhibitors represented 40 countries.
Panel sessions, keynote speeches, and technical papers spanned the breadth and depth of the oil and gas industry.
At one panel session, energy ministers and national oil company senior executives shared their perspectives on how the industry should adjust to address energy challenges as well as how the role of companies and governments should change to shape the future. The panel was moderated by Gamal Hassan, chief executive officer of ADHIG and OTC Program Chairman.
The panel began with Jose de Vasconcelos, Angola’s Minister of Petroleum, who highlighted the connection between the need for energy and economic and social development. The industry faces many challenges in the quest to obtain energy security, which he defines as an equilibrium between supply and demand. Several challenges must be addressed to meet production needs: technologic, environmental, regulatory, and financial. Angola, he said, will maintain a permanent dialog with other producers to develop a common approach on energy and energy-related issues.
David Ramsay, Minister of Industry, Tourism, and Investment, Northwest Territories, Canada, said that the role of government is to ensure that resources are “developed in a manner that brings economic development while ensuring the environment and its benefits” and at the same time working with industry and regulatory agencies to achieve this. Ramsay said that there is a renewed interest in the Arctic and northern Canada with opportunities onshore and offshore. The Canadian government is building infrastructure to assist in the transportation of fuels.
Petrobras Chief Executive Officer Maria das Gracas Silva Foster said that exploration is a priority, and major investments that have been sustained over several years have resulted in the development of a diversified and competitive goods and services. Petrobras has benefited from a close association with universities to facilitate research in exploration and development, and the recent major discoveries as well as monetization of these reserves are a direct result of the investments in research and universities.
Technology Focus: Reservoir Simulation (July 2013)
Authors: Crick Martin 
Published: February 2015

Technology Focus
Looking back through previous editions of this article, I note that, in 2011, I wrote, “there’s a growing tendency in some quarters to use very simple models.” That may be true, but there is also a growing tendency among vendors to offer models with more and more features. That is how they stay in business, after all, and many of the new features solve problems we have struggled with for years. The trouble, however, is sometimes a feeling that all those features have to be used at the same time.
Let’s remind ourselves that a compositional model will never have as many components as there are distinct molecules in the reservoir fluid. The most sophisticated coupled pipeline simulator is still only an approximation of the complexity of fluid flow in pipes. Even the most advanced geomechanics simulator has a very coarse model of the over-, under- and sideburdens, and a crude approximation of often unknown boundary conditions. Building an exact model of the reservoir and production system is like seeking the end of the rainbow.
Piling on complex features can easily mask critical issues. We should always strive to use the simplest model that captures the most important physics affecting the decision we are trying to make. And judging what is “the most important” physics is the responsibility of the reservoir engineer, not the software and not the software vendor. A simulation model is only a model. And our job is to produce the reservoir, not the model.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 159274 A Novel Simulation-Model Review Process by M.R. Palke, Ryder Scott Company, et al.
SPE 159584 Dual-Continuum Modeling of Shale and Tight Gas Reservoirs by Prince N. Azom, The University of Texas at Austin, et al.
SPE 162380 Application of Streamline Simulation to Reservoir Management: Management of WAG-Injection Optimization by Mohamed Bouaouaja, Schlumberger, et al.
SPE 162045 Stochastic Uncertainty Analysis in Compositional Simulation for Giant-Gas/Condensate-Field Reservoir-Performance Prediction by E. Descubes, Schlumberger, et al.
SPE 164142 Uncertainty-Quantification Workflow for Mature Oil Fields: Combining Experimental-Design Techniques and Different Response-Surface Models by Syed Jawwad Ahmed, ADNOC, et al.
Massively Parallel Simulation of Oceanic-Gas-Hydrate Production
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 17026, ’Massively Parallel Simulation of Production From Oceanic- Gas-Hydrate Deposits,’ by Matthew T. Reagan, SPE, George J. Moridis, SPE, Craig M. Freeman, SPE, Katie L. Boyle, and Noel D. Keen, Lawrence Berkeley National Laboratory, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.
Large volumes of gas can be produced at high rates with conventional horizontal- or vertical-well configurations for long periods of time from some methane-hydrate accumulations by means of depressurization-induced dissociation. However, most assessments of hydrate production use simplified or reduced-scale 3D or 2D production simulations. This study used a message-passing-interface parallel code to make the first field-scale assessment of a large deep-ocean hydrate reservoir. Systems of up to 2.5 million gridblocks, running on thousands of supercomputing nodes, were required to simulate such a large system at the highest level of detail. The simulations begin to reveal the challenges inherent in producing from deep relatively cold systems with extensive water-bearing channels and connectivity to large aquifers. The main difficulties are water production and achieving depressurization.
Introduction
Gas hydrates are solid crystalline com-pounds in which gas molecules occupy the lattices of ice-like crystal structures called hosts. Gas hydrates occur in the permafrost and in deep-ocean sediments, where the necessary conditions of low temperature and high pressure exist for their formation and stability. Most naturally occurring gas hydrates contain methane in abundance. Not all hydrates are desirable targets for production. Of the three possible methods of hydrate dissociation for gas production—depressurization, thermal stimulation, and use of inhibitors—depressurization appears to be the most efficient. Recent studies have indicated that, under certain conditions, gas can be produced from natural hydrate deposits at high rates over long periods of time by use of conventional technology. Earlier work focused on production from vertical wells, but more-recent studies show that horizontal wells are more productive and are easier to manage, if the technology is available.
Study
The objective of this study was to use real geophysical data at the field scale to simulate a realistic 3D gas-hydrate reservoir. Previous studies focused on simple 2D modeling, 2D modeling with artificial heterogeneity, or extremely simplified (coarse-scale) 3D modeling. Through collaboration, Statoil provided real data on the geometry and geology of a known oceanic-hydrate system. The deposit is a layered system, approximately 7×5.5 km and 350 m thick. The hydrate is arranged in a series of high-permeability channels bounded by slightly-lower-permeability levees. The system is probably impermeable at the top and bottom boundaries, but may connect to an aquifer along the x–z face.
Technology Focus: Unconventional Resources (July 2013)
Authors: Chipperfield Simon 
Published: February 2015

Technology Focus
Unconventional gas is poised to enter its Golden Age and to effect positive global change if it can meet three challenges.
Consider the 7 billion people on Earth who use energy each day. Consider the World Health Organization statistic that 3% of all world health issues are related to indoor burning of fossil fuels. Consider the potential effects of global warming and the fact that gas emits less greenhouse gas than coal, currently the most prevalent energy source. As you consider this global perspective, you will recognize the biggest driver of energy demand—namely, the human desire to sustain and improve the well-being of ourselves, our families, and our communities. You will also notice the positive effect gas can have.
Through 2040, we will see enormous population and economic growth that will increase energy demand by more than 40%, according to an ExxonMobil study, with gas projected to surpass coal demand in the next decade.
Gas-driven changes have already begun. In fact, the use of gas instead of coal in the power-generation sector is already helping slow global carbon dioxide emissions, and, in the United States and other developed economies, emissions are actually falling.
Again, unconventional gas will drive further transformation if we can overcome three critical challenges.
The first is our ability to deliver the technologies necessary to unlock the vast global unconventional gas potential of more than 14,000 Tcf. For example, horizontal, hydraulically fractured wells have been a key to unlocking the shale potential in North America, but are they the ideal technology in other parts of the world, and are they ideal for coal and tight gas?
The second is our ability to deliver a cost-effective, reliable, and timely energy option for the world. For upstream engineers and geoscientists, cost-effective, efficient delivery includes the development of smart, streamlined factory processes and technologies in the field and office throughout the appraisal and development phases.
The third challenge is our demonstration of social responsibility, measured by the public. This will be based on our capability to leave the environment better than we found it, by providing jobs, supporting local investment, and maintaining the highest environmental standards.
If we can deliver in these three areas, the Golden Age of unconventional gas will occur and make a better world.
And I am confident that we will.
Recommended additional reading at OnePetro: www.onepetro.org.
IPTC 16608 Integrating an LNG Plant With an Unconventional Gas Supply by Chris Langley, Arrow Energy, et al.
SPE 162777 What Don’t We Know About Self-Sourced Oil Reservoirs: Challenges and Potential Solutions by Steve Larter, University of Calgary, et al.
SPE 163987 Optimizing Remote Unconventional Gas Exploration by Martin Rylance, BP
SPE 149872 Stimulation Unlocks Coalbed Methane: Lessons Learned in India by Shahvir Pooniwala, Baker Hughes
Liner-Based Stimulation Technology Without Fracturing Proven in Field
Authors: Jorgensen Thomas 
Published: February 2015

Technology Update
Efficient production in many fields requires reservoir stimulation. Some of the challenges with hydraulic fracture stimulation are reservoir-related, such as consistently stimulating all targeted intervals. The growth of hydraulic fractures in the vertical direction is difficult to predict, leading to the risk for entering unsought gas- or water-bearing formations. Operations can be complex, costly, and pose environmental challenges.
A new liner-based stimulation technology has been developed and field tested by Fishbones to be simple, efficient, and more controllable with less environmental impact. The method uses less fluid and reduces greatly the risk of groundwater contamination and the disposal of recovered stimulation fluid. Field experience has shown positive productivity response, with an 8.3 times increase in 30-day cumulative initial production (IP-30) in an existing well in a tight limestone formation. The productivity index was increased by 30 times.
The liner-based stimulation technology was originally developed for carbonate reservoirs, but is also applicable in coalbed methane and unconsolidated formations. Technology suitable for sandstones and other clastic formations is being developed.
Technology Description
The technology uses a liner sub that houses four small-diameter, high-strength tubes called needles, each with a jet nozzle on the end (Fig. 1). The sub is made up to a full-length casing joint and needle assemblies up to 40 ft long are assembled in the workshop before the sub is sent to the field.
The subs are run as integral parts of the liner in the open hole and are positioned across the formation where stimulation is desired. The needles are located inside the sub/liner joints while the sub is run in hole. The liner is hung off with a standard liner hanger.
In a carbonate formation, a basic hydrochloric acid (HCl) fluid system is pumped. The fluid jets out of the nozzles, and the formation ahead of the tubes is jetted away by a combination of erosion and acid chemical dissolution. Differential pressure across the liner drives the needles into the formation, and they penetrate the rock until fully extended. Typical jetting pressure is 3,000 psi.
All laterals are created simultaneously in a short pumping job, resulting in a fishbone-style well completion with multiple laterals extending from the main bore (Fig. 2). The rate of penetration depends on the formation composition, porosity, downhole temperatures, nozzle configuration, jetting fluid, and jetting pressures. The needles exit the sub at an approximate 40° angle. The bending through the exit port results in laterals with an approximate 90° angle relative to the wellbore.