bluuebunny/crossref_metadata_2025_split huggingface dataset:
Unplanned Downtime in the Gulf of Mexico: A Significant Production Loss Management Opportunity for Producers
Authors: Tucker Richard M. , Straub Tom , Feng Shu 
Published: February 2015

Management
An analysis of 190 US Gulf of Mexico (GOM) producing assets in Ziff Energy’s field level operations database reveals significant opportunities for improving operating efficiency by reducing downtime. Total (planned and unplanned) production efficiency (PE) of these assets was found to be 88%.
Of the 12% production loss relative to potential (no downtime) production, 8% was a result of unplanned downtime, while 4% was either planned (i.e., accounted for in the company’s annual budgets) or a result of external causes, such as weather. This result indicates significant potential exists to increase production by reducing the frequency and duration of unplanned downtime (Fig. 1).
Economics of Improved Production Efficiency
The exploration and production (E&P) sector is historically a 10% to 15% rate of return business, which means that the last 10% to 15% of production is profit. If an operator could eliminate or reduce half of the 8% unplanned production loss, it could potentially double the rate of return from its assets. Because production loss management often can be done at small expense or investment, no other activity has the same potential to positively affect the bottom line. In short, production loss management is the best “margin lever” in the E&P business.
Based on 5-year (2008–2012) aver-age of GOM production of 1.39 million B/D of oil and 5,932 MMcf/D of gas, the additional annual production from recovery of all unplanned losses in the GOM could reach 102,000 B/D of oil and 582 MMcf/D of gas respectively (Fig. 2). The annual value of the recovered oil alone (without considering gas) would exceed USD 3 billion/yr. Deepwater rep-resents almost 80% of unplanned oil losses. Shelf gas, which accounts for more than half of total gas produced in the GOM, accounts for two-thirds of the unplanned gas losses.
Uptime Reliability Metrics
Ziff Energy has defined a family of metrics to assess uptime reliability. To determine production loss, an estimate of production capacity called predicted production capacity (PPC) can be used. Total production loss is the volumes of lost production due to all reasons. The total loss is derived by comparing actual annual production with PPC and consists of the following components:
Planned loss: Production loss because of scheduled downtime for repairs and maintenance or new well/facility tie-ins. An event is “planned” only when it is included in the annual budget. It should be noted that improvements in planned downtime are possible if the duration and frequency of planned events can be reduced resulting in improved production efficiency.
Unplanned loss: Production loss because of equipment/facility failures or operational upsets.
External loss: Production loss caused by external reasons, which are further broken down into midstream downtime, market limitations, and weather restrictions.
High-Reliability Gas Lift Flow-Control-Device Technology and Erosion/Endurance Tests
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 159848, ’High-Reliability Gas Lift Flow-Control-Device Technology and Erosion/Endurance Tests,’ by Jun Xu, Stuart L. Scott, SPE, and Wayne Mabry, SPE, Shell E&P, and Jose Gamboa, SPE, The University of Tulsa, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8-10 October. The paper has not been peer reviewed.
High-reliability gas lift flow-control devices (GLFCDs) enable gas lift for wells with the potential for H2S in the produced gas and where casing is not qualified for H2S service. Valve specifications are such that no leakage is allowed at both high (8,000-psi) and low (1-psi) differential pressures across the valve. A series of tests was designed using the environmental-stress-screen (ESS) concept and a harsh test standard that greatly exceeds API specifications for GLFCDs.
Introduction
GLFCDs are usually incorporated into the production conduit and used to inject high-pressure natural gas from the injection conduit to the interior of the production conduit. Commercially available GLFCDs typically contain one-way check systems comprising a ball, hemisphere, or cone, which is pressed against a valve-seating ring by a spring. Unfortunately, many GLFCDs are prone to wear and damage because of fluid cut during the operation.
Some of Shell’s Gulf of Mexico deepwater wells commonly produce sour fluids, which the casing program was not designed to tolerate. When sour production enters casing that is not qualified to National Association of Corrosion Engineers standards, the wells cannot be produced. Therefore, a family of high-reliability GLFCDs has been developed for use in deepwater/subsea associations. This technology is viable for any gas lift well because of significant cost savings in change-out of GLFCDs and the ability to maintain well integrity. Fig. 1 presents schematics of the GLFCD through which liquids are unloaded from the casing annulus into the tubing, while Fig. 2 details several types of high-reliability GLFCDs.
High-Reliability-GLFCD Design Validation and Qualification Procedures
A series of design validation and qualification tests has been established and executed to determine whether high-reliability GLFCDs meet the acceptance criteria of API or ISO standards and Shell specifications and qualifications. Shell’s test program for these GLFCDs comprises three parts: factory acceptance, qualification, and endurance. Every individual GLFCD that has passed all factory-acceptance tests would be deemed accepted for installation and service. If the prototype of a GLFCD has passed Shell tests, it is deemed qualified to be a high-reliability GLFCD. Currently, three gas lift manufacturers have developed GLFCDs and products that have been tested using Shell’s test program; these test results are described in the following sections.
CO2-Sequestration Projects Adding Value
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 17089, ’The Plains CO2-Reduction Partnership: CO2-Sequestration Demonstration Projects Adding Value to the Oil and Gas Industry,’ by Charles D. Gorecki, Edward N. Steadman, John A. Harju, James A. Sorensen, John A. Hamling, SPE, Lisa S. Botnen, Scott C. Ayash, and Katherine K. Anagnost, Energy & Environmental Research Center, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.
Carbon capture, use, and storage (CCUS) in geological media can be an important means for reducing anthropogenic greenhouse-gas emissions. Several geological settings are appropriate for geological storage of carbon dioxide (CO2), including depleted oil and gas reservoirs, deep brine-saturated formations, CO2-flood enhanced-oil-recovery (EOR) operations, and enhanced coalbed-methane recovery. The US Department of Energy is pursuing a program to demonstrate CCUS technology through its Regional Carbon Sequestration Partnership (RCSP) program.
Introduction
The Plains CO2 Reduction (PCOR) partnership, led by the Energy & Environmental Research Center, is one of seven regional partnerships established under the RCSP program. The PCOR partnership region includes all or part of nine US states and four Canadian provinces (Fig. 1) and is made up of many private- and public-sector groups working to identify the most-suitable CO2-storage strategies and technologies, aid regulatory development, educate the general public, and investigate appropriate infrastructure for CCUS commercialization within its region. The Phase-III program includes two commercial-scale projects—the Fort Nelson carbon- capture and -storage (CCS) feasibility project and the Bell Creek CO2-EOR/CO2-storage project.
Fort Nelson. The PCOR partnership and Spectra Energy Transmission are investigating CCUS to mitigate CO2 emissions produced by the Fort Nelson Gas Plant (FNGP) as a waste stream from natural-gas processing. FNGP is near the town of Fort Nelson in northeastern British Columbia, Canada (Fig. 2). The gas stream will include up to 5% hydrogen sulfide (H2S) and a small amount of methane (a sour-CO2 stream). The goal is to capture the stream of sour CO2 that is separated by the current gas-processing operations and store it long term in a deep saline formation. Currently, this sour CO2 is processed in an existing sulfur plant to recover elemental sulfur, and the residual CO2 and sulfur dioxide (SO2) are passed through an incinerator before venting to the atmosphere.
How Thirsty is Shale Gas?
Authors: Rao Vikram 
Published: February 2015

Beyond the Headlines
Editor’s note: Professionals in the oil and gas industry often receive questions about how industry operations affect public health, the environment, and the communities in which they operate. Of particular concern today is the impact of hydraulic fracturing on the environment. In this new column, JPT is inviting energy experts to put those questions and concerns about industry operations into perspective. Additional information about the oil and gas industry, how it affects society, and how to explain industry operations and practices to the general public is available on SPE’s Energy4me website at www.energy4me. org.
The New York Times reported on 15 May 2014 that Butte County in California banned hydraulic fracturing because of concerns regarding freshwater consumption in a drought year. Shale oil and gas opponents have seized this issue even in parts of the country not suffering any significant drought. The perception of being deprived of drinking water has strong imagery. The facts beyond the headlines are decidedly not so dire.
A single shale oil or gas well will use between 3 and 5 million gal of water for drilling and completion operations. This sounds like a lot and, in some sense, it is a lot. But then you realize that the average golf course uses that much every 25 days, about the length of time it takes to drill a single well and start producing from it. It is also the amount of water that New York City uses every 4 minutes! Not a fair comparison, you say. Well, why don’t we compare it against other forms of energy?
Such comparisons are best made on the basis of liters of water per megawatt hour of energy. Shale gas production uses about 38 liters. In comparison, corn ethanol on average uses 32,000 to 370,000 liters (the higher end of the range is for irrigated corn), and the real shocker is soybean diesel, which comes in at 180,000 to 960,000 liters. In other words, corn ethanol uses more than 1,000 times more water per unit of energy compared with shale gas. Other sources suggest an even greater disparity in water usage (Science 2009).
Conventional fracturing fluid uses freshwater as the base fluid. Fresh is defined as 500 parts per million (ppm) or less of dissolved solids. The fluid returning to the surface after use, known as flowback water, is always saltier than what went in. Salinities of 200,000 ppm are not uncommon. As a frame of reference, seawater runs about 35,000 ppm. Recent advances in fracturing fluid chemistry allow for such flowback water to be reused without removing the salt down to fresh standards. Currently in the Marcellus shale play, some companies are reusing almost all of their flowback water with minimal treatment.
Unconventionals, Technical Challenges Highlight Offshore Technology Conference
Authors: Betz Jack , Carpenter Chris , Henni Abdelghani , Jacobs Trent , Parshall Joel , Rassenfoss Stephen , Wilson Adam 
Published: February 2015

Conference Review - 2014 Offshore Technology Conference
The impact of onshore unconventionals development on the offshore sector, safety and environmental protection, and new opportunities and their technical challenges highlighted sessions and discussions during the annual Offshore Technology Conference (OTC), held 5–8 May in Houston. The broad program and exhibition, which attracted a record crowd, featured operators, independents, service companies, academia, and government officials weighing in on some of the most complex and pressing challenges facing the offshore industry.
The surge in North American shale development has brought major portfolio changes to E&P companies. This was the focus of one session in which six panelists discussed the impact of the unconventional “revolution” on the offshore deepwater industry.
Darrell Hollek, senior vice president for deepwater Americas operations and development at Anadarko, noted the huge change in his company’s production mix in the past 4 years. “If you go back (only) as far as 2010, we really had not drilled any horizontal wells,” he said. From that base of virtually no shale production, Anadarko has ramped up to production of 370,000 BOE/D from unconventional resources in 2014, and unconventional plays represent about 70% of the company’s capital budget, Hollek said.
Nonetheless, Anadarko’s mid-cycle and long-cycle projects—chiefly offshore activity, including deepwater projects— play a crucial role through generating high cash flow that has financed the company’s entry into onshore unconventional development, Hollek said.
Qatar Focuses on Building Energy R&D Capacity
Authors: Henni Abdelghani 
Published: February 2015

Qatar R&D activities
Innovation and R&D have become top priorities for governments in the Middle East, mainly in the Gulf region. Qatar is striving to take the lead in this domain and has unveiled an ambitious plan to become the region’s energy R&D center now that it has completed a massive liquefied natural gas (LNG) production upgrade as part of its strategy to monetize its vast gas reserves.
Qatar’s plan to establish itself as a center of energy R&D is in line with its National Vision 2030, which aims to transform the nation from a hydrocarbon-based economy into a knowledge economy.
“R&D and technology have been at the heart of Qatar’s energy sector for many years, allowing it to unlock and commercialize the North Field’s vast gas reserves, and grow the country into the world’s largest LNG exporter,” said Hamad Rashid Al Mohannadi, chief executive officer of RasGas Company and chairman of the Board of Regents at Qatar University. He spoke recently at the Gulf Intelligence Qatar Energy R&D Forum in Doha in a presentation titled, “Qatar Energy R&D Next Steps - Moving from the Theoretical to the Specific.”
“Going forward, they will continue to play an important role in ensuring the sustainability of our industry, whose economic support underpins the ambitious Qatar National Vision 2030,” he said. “Qatar is blessed with a number of rooted establishments that enjoy strong financial backing to help set the direction for and facilitate these R&D and technology efforts. Our focus today should be on collaborating to effectively and efficiently address the grand challenges of energy, water, and cybersecurity.”
Faisal Alsuwaidi, president of research and development at the Qatar Foundation for Education, Science, and Community Development, said that Qatar energy officials have identified 72 objectives for a research agenda, “all of them with targets for sustainable development to improve the quality of life.”
Fracture Stimulation in the First Joint-Appraisal Shale-Gas Project in China
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16762, ’Successful Fracture Stimulation in the First Joint-Appraisal Shale-Gas Project in China,’ by Liang Jin, Changlong Zhu, Yong Ouyang, Ming Zhou, Qingguang Qu, Fei Li, Roger Yuan, Chris Wu, Zhiyi Zhang, Yan Wang, and Fa Dwan, Shell China Exploration & Production; Sanjay Vitthal, Shell Canada; and Shiqian Wang, PetroChina Southwest, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.
This paper discusses fracture stimulation in the first joint-venture shale-gas project with foreign companies in China. The block is in Sichuan province, and the target zone is Longmaxi hot shale, a Silurian formation. Its matrix permeability is extremely low (100 to 300 nanodarcies), but it is rich in natural fractures. Hydraulic fracturing has been shown to be critical to enhancing production. A collaborative approach was applied to the completion of the shale gas wells during appraisal.
Introduction
Most of China’s proved shale-gas resources are in the Sichuan, Tarim, and Ordos basins. China’s technically recoverable shale-gas resources are estimated at 1,275 Tcf. The operator jointly appraised a shale-gas block in Sichuan with PetroChina. The project team needed to make several determinations in the early phase of the project, such as whether there is sufficient gas in the shale formation and whether the gas can be extracted at a high-enough (commercial) rate. From the production technologists’ perspective, the technical objectives of the early wells included the following:
Test the ability of the Longmaxi hot-shale interval to be fractured under high formation pressure.
Establish baseline fracture designs for the Longmaxi hotshale interval, at greater than 3500-m true vertical depth (TVD), and systematically evaluate the design parameters.
Establish an effective multidisciplinary workflow.
Gather fracture-stimulation-performance data and subsurface-pressure information.
Determine the productivity of the gas from the appraisal wells to prove the presence of a shale-gas play.
The joint-appraisal phase began in November 2010. While planning the drilling of deep wells to evaluate the Longmaxi formation, data were obtained from several shallow wells at a location close to the surface. Extensive laboratory tests were conducted to evaluate the geochemical properties of the rock. In addition, some rock-mechanics properties were measured. The drilling of the first well (Well A) began in December 2010, and hydraulic fracturing began once the well reached designed depth. To date, five wells have been drilled; two are vertical, and three are horizontal.
Unconventional-Reservoir Development in Mexico
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164545, ’Unconventional-Reservoir Development in Mexico: Lessons Learned From the First Exploratory Wells,’ by P.A. Parra, N. Rubio, C. Ramirez, B.D. Guerra, V.A. Exler, I.R. Campos, M.D. Trejo, J. Olguin, C.H. Vargas, R. Valbuena, D.F. Soler, M.I. Weimann, V. Lujan, and P. Bonningue, Schlumberger, and P.G. Reyes, R. Martinez, R. Munoz, E. Rodriguez, and M. Garcia, Pemex, prepared for the 2013 SPE Unconventional Resources Conference—USA, The Woodlands, Texas, USA, 10-12 April. The paper has not been peer reviewed.
In 2010, exploration of gas-rich and possibly liquid-rich shale reservoirs began in northern Mexico. A two-stage integrated workflow was developed to achieve set objectives. The drilling stage used a petrophysical and geomechanical static model to identify the most prospective interval in the reservoir, define the best drilling azimuth and landing point, and reduce drilling risk. Real-time geosteering was implemented to achieve the targeted navigation window. In the completion stage, reservoir-centric completion-and-stimulation software was used to optimize completion and stimulation design.
Introduction
The initial target formation was the Upper Cretaceous Eagle Ford; the second was a Jurassic formation locally called Pimienta.
The Eagle Ford shale is a Late Cretaceous hydrocarbon-producing formation composed of organic-rich calcareous mudstones with mineralogical composition with ranges of 5–20% quartz, 15–25% clay, and 65–80% carbonate, and with a total-organic-carbon (TOC) range of 1–6%. The Eagle Ford shale is overlain by the Austin chalk and overlies the Buda limestone. It has been divided into two units, a lower unit deposited during transgressive sequences and an upper unit deposited in a regressive sequence. Both units were deposited in a low-angle sloping ramp. As of July 2012, five wells had been drilled in the Eagle Ford formation: AEF, BEF, CEF, DEF, and EEF.
The origins of the Pimienta formation date to the Late Jurassic. It is an organic-rich source rock with potential for hydrocarbon production as an unconventional reservoir. Its mineralogical composition exhibits ranges of 20–40% quartz, 25–45% clay, and 20–40% carbonate, with an average TOC range of 3–4%. As of July 2012, one well (AP) had been drilled in the Pimienta formation.
Unconventional-Asset-Development Work Flow in the Eagle Ford Shale
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 168973, ’Unconventional-Asset-Development Work Flow in the Eagle Ford Shale,’ by David Cook, Kirsty Downing, Sebastian Bayer, Hunter Watkins, Vanon Sun Chee Fore, Marcus Stansberry, Saurabh Saksena, and Doug Peck, BHP Billiton Petroleum, prepared for the 2014 SPE Unconventional Resources Conference - USA, The Woodlands, Texas, USA, 1-3 April. The paper has not been peer reviewed.
Development of the Eagle Ford shale typically consists of horizontal wells stimulated with multiple hydraulic-fracture stages. This paper presents a pragmatic integrated work flow used to optimize development and guide critical development decisions in the Black Hawk field. Geoscientists and reservoir and completion engineers worked collaboratively to identify optimal completion designs and well spacings for development focus areas. Multiple simplistic simulation models were history matched to existing production wells.
Introduction
In 2008, the operator drilled several successful wells in the Hawkville field of what would become the Eagle Ford shale play. Early results led to substantial land acquisition. The Eagle Ford, while continuous over wide sections, varies substantially in terms of fluid and rock properties. Fig. 1 shows a cross section for an arbitrary line through Black Hawk and Hawkville to the Maverick basin, showing the relative changes in thickness and Young’s modulus.
An understanding of the characterization of shale systems for simulation has evolved rapidly. Flow contributions from natural fractures, induced fractures, and matrix rock along with the nature of the hydrocarbon deposit itself should be considered. Perhaps even more important is regional variation. In the world of conventional assets, property estimation needs to be reliable only for a small geographical area, often within one sandstone structure of a few square miles at most. This can be compared with the scale of the play in Fig. 1. For conventional reservoirs, standardized laboratory methods and years of research and trial and error have educated our approaches to well-defined best practices. In shale plays, these have not yet been fully worked through and adopted by consensus, often leaving the owner of the asset as the arbiter of methodology.