bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Ultradeepwater Heavy-Oil Development Offshore Brazil
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 20537, ’Parque das Conchas BC-10 - An Ultra- Deepwater Heavy Oil Development Offshore Brazil,’ by K.H. Stingl, Shell International E&P, and A. Paardekam, SPE Shell Brazil E&P, originally prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed.
Parque das Conchas is an ultradeep-water heavy-oil development in the northern Campos basin offshore Brazil. The project is a joint venture between Shell, Petrobras, and Oil and Natural Gas Corporation of India. The first phase of the project is the development of three independent subsea fields tied back to the centrally located turret-moored floating production, storage, and offloading (FPSO) host facility, the FPSO Espirito Santo.
Introduction
The Parque das Conchas development grew out of a substantial exploration and appraisal program beginning in 2000 in which 13 wells were drilled and six discoveries were made. The Declaration of Commerciality was signed with the Brazilian National Petroleum Agency in December 2005, and the project was sanctioned in November 2006. The four main reservoirs—Ostra, Abalone, Argonauta B west, and Argonauta O north—were named after shellfish indigenous to the area. Together, they form “Parque das Conchas,” or “Shell Park,” in Portuguese. This is the first project in Brazil taken by Shell from exploration discovery to production. First oil from Phase 1 was achieved on 12 July 2009, just 9 years after discovery.
Development
Abalone, Ostra, and Argonauta B west are small-to-medium in size and stratigraphically complex, with highly faulted, compartmentalized, unconsolidated sand packages. The reservoir pressures are low, and the oils range from heavy to light, ranging in gravity from 17 to 42°API. A fourth heavy-oil field, Argonauta O north, will be tied back as part of Phase 2 and is planned to be ready for production in 2013. The Argonauta O north field contains 16°API oil and will require waterflood for reservoir-pressure support.
The Phase 1 subsea infrastructure consists of 10 producing wells and one gas-injection well connected by 100 km of insulated and uninsulated flowlines ranging in size from 6 to 12 in., 15 flow-line sleds, two production manifolds, two artificial-lift manifolds housing a total of six vertical subsea-separation caissons with 1,500-hp electrical submersible pumps (ESPs), and 25 rigid jumpers, all of which are serviced by approximately 30 km of multicircuit high-voltage electrohydraulic (HVEH) umbilicals connected to the FPSO.
The gas is processed on the FPSO, and to avoid flaring and to reduce CO2 emissions, it currently is being injected into a gas-injection well. A dedicated 40-km-long 6-in. uninsulated Parque das Conchas trunkline has been installed from the FPSO and will be tied into the Petrobras Caipixaba gas-export pipeline at the Petrobras BC-60 location scheduled to be operational in 2010. The oil is stored on the FPSO and offloaded to shuttle tankers as required.
Technology Focus: Tight Reservoirs (October 2010)
Authors: Kubala Gregory 
Published: February 2015

Technology Focus
Shale-gas reservoirs are becoming an increasingly significant percentage of the global tight-reservoir landscape. Three questions reflect this increasing dominance but are applicable overall to tight formations.
Is the long multistage-fractured horizontal well into which millions of gallons of water are pumped downhole with only a third of the contacted reservoir propped open the most efficient way to produce the reservoir?
Is the long multistage-fractured horizontal well the endgame solution to Master’s Resource Triangle?
If the equations set forth by Darcy and Young/Laplace are valid, does contacting a large amount of the formation with only water constitute stimulation of the reservoir?
Capillary pressure is significant in tight reservoirs. Stimulation-fluid invasion into smaller pore diameters and invasion of proppant-free stimulation fluid into both induced fractures and dilated natural fractures will have an effect. Production-decline rates and long-term health of wells (improved fluid flow or degree of formation damage) in tight reservoirs will depend on how capillary forces are managed in the reservoir.
Log-normal large volumes of hydrocarbon found in tight reservoirs are difficult to develop because of constrained drainage areas, complicated petrophysics, lithology, and formation heterogeneity. These difficulties, complexities, and heterogeneities dictate planning of drilling, completion, and stimulation specific to the well in question. They also dictate continued advances in knowledge and technology if the majority of the hydrocarbon asset is to be produced effectively.
Early production levels will be dependent on the length of propped fracture from the wellbore that has actually cleaned up and this contributing to hydro-carbon flow.
Our industry needs to make advances in: real-time measurement; post-fracture monitoring with production analysis; identifying sweet spots, then placing perforations to create complex conductive fractures; innovative proppants and proppant-placement techniques in primary and complex fracture geometries; fluid recovery; formation-damage control and permeability enhancement; proppant transport with less-damaging stimulation fluids; and environmentally responsible drilling, completion, and production services.
Tight Reservoirs additional reading available at OnePetro: www.onepetro.org
SPE 128191 • “Selecting Drilling Technologies and Methods for Tight Gas Sand Reservoirs,” by Pilisi, N., SPE, Blade Energy Partners, et al.
SPE 131778 • “Using Microseisms to Monitor Hydraulic Fractures in the Bakken Formation of North Dakota,” by Gary S. Forrest, Schlumberger, et al.
SPE 130043 • “Fracturing Design Aimed at Enhancing Fracture Complexity,” by M.Y. Soliman, Halliburton, et al.
Technology Focus: Sand Management and Frac Pack (October 2010)
Authors: Goodman Harvey E. 
Published: February 2015

Technology Focus
As our wellbore-integrity- and sand-management-modeling prowess grows from the laboratory to the field, the quest for reliable environmentally responsible energy resources continues to challenge, and in some cases demands, us to accelerate development of new well-system-integrity applications for the field. Well-engineering-systems design benefits from formation-failure-prediction modeling capabilities that can be verified in the field by a more diverse array of measurement techniques in both open- and cased-hole environments, even extending to the overburden by use of geophysical-survey techniques. Still, we are challenged to integrate the formation-failure predictions and observations with well-systems hardware and architecture that define the entire production system, from the completion up to the wellhead, and on through the surface facilities.
Papers selected for this month’s feature start with risk-based well integrity for CO2 storage in the subsurface. To ensure CO2 containment over time, well-integrity-modeling technology is pushed to its limits. The risk-based approach is introduced to manage the complexities of long-term storage.
A second paper looks at the basics of sand-exclusion-performance evaluation after a change in long-standing completion practice was made to shorten project-payout time. The paper examines this decision from the viewpoint of longer-term production performance.
The third paper deals with wellbore integrity in chemically active shale formations. The work experimentally investigates the effects of capillary pressure and osmotic forces on shale-swelling behavior. The study questions the practice of adjusting only the salinity concentrations in the aqueous phase of drilling muds to enhance hole stability by pulling water from the shales into the borehole to retard hydration (chemical osmosis). Could the highest saline concentrations cause associated water to move into the shales through ion transfer by diffusion osmosis?
Sand Management and Frac Pack additional reading available at OnePetro: www.onepetro.org
SPE 128038 • “Improved Selection Criteria for Sand Control—When Are ‘Fines’ Fines?” by Michael Byrne, SPE, Senergy, et al.
SPE 127931 • “State-of-the-Art Screen Selection for Standalone-Screen Applications” by R.A. Chanpura, Schlumberger, et al.
SPE 123478 • “A Comprehensive Study of Sanding Rate From a Gas Field: From Reservoir, Completion, and Production, to Surface Facilities,” by Gang Han, Hess Corporation, et al.
A Risk-Based Approach for Well-Integrity Management for a CO2 Geological Storage Project
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 122510, ’A Risk- Based Approach for Well Integrity Management Over Long Term in a CO2 Geological Storage Project,’ by Y. Le Guen, SPE, V. Meyer, O. Poupard, E. Houdu, and R. Chammas, SPE, Oxand S.A., originally prepared for the 2009 SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, 4-6 August. The paper has not been peer reviewed.
A risk-based methodology associated with well integrity is proposed within CO2 geological storage. The main objectives of this approach are to identify and quantify risks associated with CO2 leakages along wells over time (from tens to thousands of years), to evaluate risks, and to propose relevant actions to reduce unacceptable risks.
Introduction
Concerns about greenhouse-gas emissions are growing. Both authorities and industries are thinking about solutions to reduce their emissions to adhere to the convention signed in Kyoto. The carbon capture and storage (CCS) technology constitutes one of the most suitable technologies to reduce greenhouse-gas emissions in the atmosphere. Pilots already exist worldwide. However, a large-scale deployment can be questioned for some of them. Among various issues, public fear, environmental impacts, economical aspects with respect to CO2 geosequestration, and possible gas leakages still constitute major issues. Wellbores constitute the only intrusive and manmade element of the storage system in the geologic systems. Moreover, the wellbore-integrity assessment implies a number of specificities, because of the time scales involved, the properties of the stored fluid and to the uncertainties characterizing the physical parameters and mechanisms. Demonstrating that the wellbore constitutes a safe barrier for CO2 confinement over the long term is of paramount importance for large CCS acceptance and deployment.
The full-length paper presents a quantitative risk-based methodology to evaluate the performance and the risks associated with well integrity in the long term, taking into account the degradations and aging of the components of the well coupled to porous-media flow occurring in a well. A statistical approach is integrated into the methodology to deal with the uncertainties associated with both the well characteristics and the input to the model. To illustrate the methodology and demonstrate its relevance to provide operators with operational recommendations, a synthetic case study is proposed.
Performance and Risks Methodology
The present methodology has been developed in accordance with a risk-based process. Here, risk is not just a concept but also a metric that can be quantified. Risk can be defined as the combination of the likelihood of a failure event (i.e., its probability) and the magnitude of its impact. The uncertainties of the system are converted into the notion of probability, and the quantitative CO2-leakage mass assessed into the notion of severity.
Technology Focus: Knowledge Management and Training (October 2011)
Authors: Ellul Ivor 
Published: February 2015

Technology Focus
Past articles for this feature have touched on the topic of decision making. Indeed, last year’s article tackled the approach to decision making with a focus on situational awareness. This year, we focus on the availability of knowledge as an aid (on the one hand) and a prerequisite (on the other) to our ability to execute decisions rapidly and correctly.
Distilling the key paper topics offered up for this year’s Knowledge Management and Training feature resulted in an interesting “triple-S” configuration of systems, state, and studies.
Systems. Knowledge-base (KB) systems are becoming a key component in the workflow for delivering critical decision making. The industry has transcended what may now be considered standard databases. A variety of database configurations is available commercially, with great advances made over recent years. Overlaying available data with information and carefully collated knowledge is an emerging practice. Delivering the KB within a spatial frame of reference, commonly a geographical-information system (GIS), provides for a rich degree of multidimensionality.
State. Continuous access to the “state” of the integrated asset, including the reservoir, production, and pipeline systems, is readily available by use of now-commonplace supervisory control and data-acquisition systems. However, the ability to translate the state into meaningful information requires transfer through a series of process layers that filter and aggregate the data such that action may be taken as necessary and appropriate to maintain production targets.
Studies. The industry invests significant capital in conducting detailed integrated studies of assets at various points in their life cycles. While keeping internal and external consulting organizations in business, these studies usually deliver an enhancement, depending on the degree of acceptance of the recommendations. Additionally, depending on the organization, the shelf life of these studies may be somewhat limited. Any approach is, therefore, welcomed if an integrated study is incorporated within an enterprise decision-making frame of reference.
And the learning process continues….
Knowledge Management and Training additional reading available at OnePetro: www.onepetro.org
SPE 145080 • “Reservoir Engineering for Unconventional Gas Reservoirs: What Do We Have To Consider?” by C.R. Clarkson, University of Calgary, et al.
SPE 144321 • “Integrating All Available Data To Improve Production in the Marcellus Shale” by Efe Ejofodomi, Schlumberger, et al.
OTC 21491 • “GIS Development for Geophysical- and Geotechnical-Data Integration: Application to West Africa Geohazard Assessment” by G. Dan-Unterseh, Fugro France SAS, et al.
OTC 21538 • “GIS Technology Development for Sediment Characterization of Angolan Deepwater Soil Conditions” by M. Hamon, Angolan Deepwater Consortium (Doris Engineering), et al.
Selecting a Completion Strategy for Sand Control and Optimal Production Rate - Unayzah Sandstone Reservoir
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 131078, ’Selection of Completion Strategy for Sand Control and Optimal Production Rate - Field Examples From Saudi Arabia's Unayzah Sandstone Reservoir,’ by Zillur Rahim, SPE, Bandar Al-Malki, SPE, and Adnan Al-Kanaan, Saudi Aramco, prepared for the 2010 SPE Asia Pacific Oil & Gas Conference and Exhibition, Brisbane, Australia, 18-20 October. The paper has not been peer reviewed.
For field development, it is important to identify reservoir structure, heterogeneity, rock properties, and fluid characteristics to select an optimal development strategy for enhancing production and increasing recovery in a cost-effective manner. Therefore, a detailed reservoir description and characterization is required by use of geo-physical, geological, and engineering data. This condensate-rich, high-flow-capacity, and highly sanding deep gas reservoir was developed gradually and optimized to select the most appropriate drilling-and-completion technique.
Introduction
Saudi Aramco’s SA-1 field produces from the Permian Unayzah formation. The first well drilled penetrated the Unayzah-A zone in 1997 and showed excellent reservoir quality. Cores were collected from the well and, subsequently, from other wells confirming unconsolidated reservoir rock with low Young’s modulus and compressive-strength values.
To avoid sanding during production, early wells in this field were completed as vertical wellbores with frac-pack stimulation using premium screens, even though difficulties were encountered during frac-pack installation. With technology advances in drilling and completion, the development method shifted to drilling horizontal and highly slanted holes. This method eliminated deploying the frac-pack system, increased reservoir contact substantially, and improved well performance. To protect well integrity and eliminate sand production, expandable sand screens (ESSs) were used for completing the wells. Higher sustained gas rates were achieved with a reduced non-Darcy skin, sanding was eliminated, and risks related to deployment of the completion equipment (ESS) were reduced.
Getting Beyond Gasland
Authors: Rao Vikram 
Published: February 2015

Guest editorial
No shale gas production issue may be more fraught with partisan rhetoric than the possibility of methane in drinking water. Flaming faucets make for great imagery no matter the actual frequency of occurrence.
Well water contamination is personal and frightening. Carbon dioxide in the air barely registers on the average personal anxiety scale, but the quality of well water makes for avid reading and activism. In the case of shale gas, the industry response has been sweeping in denial. Both sides are playing fast and loose with the English language.
Shale gas operations can contaminate aquifers in potentially two ways. One would be through the leakage of chemicals used in fracturing (i.e., a liquid contaminant). The second would be the infiltration of aquifers by produced methane, a gaseous contaminant. If present, a portion may be released as a gas, as spectacularly depicted in the well-publicized documentary Gasland. Natural occurrences such as the Eternal Flame Waterfall in the Shale Creek Preserve in New York demonstrate methane intrusion into a freshwater source. The name follows from the fact that the gas remains lit with a visible flame under the rock overhang of the waterfall.
Methane is odorless and colorless, so it is hard to identify. It leaves no taste in the water, but can be hazardous if it collects in an enclosed space. When used in commerce, the industry deliberately adds mercaptans, a smelly substance (travelers on the New Jersey Turnpike near refineries know the smell well) for added safety. Gas leaks in a commercially supplied setting, such as a kitchen or furnace, are therefore detectable by smell. Leaks from a well would not be detectable by smell.
Natural contamination is either from relatively shallow biogenic methane or from thermogenic gas from deep deposits escaping upward along faults and fissures. The latter are generally caused by tectonic activity. The two types of gas leave fairly different fingerprints and often can be distinguished on that basis. Good oil and gas exploitation practitioners will avoid producing in areas with significant vertical leak paths because they impair normal sealing mechanisms.
Despite the seemingly sound scientific fingerprint techniques available, identifying the source of gas is subject to interpretation. This is particularly the case when, within the class of thermogenic origin, efforts are made to identify the age of the rock from which the leakage took place. In principle, both the isotope signature and the natural gas liquids (NGL) content have relationships with rock age. These relationships are not always well behaved enough to be unequivocal.
Sensabot: A Safe and Cost-Effective Inspection Solution
Authors: JPT staff _ 
Published: February 2015

Young Technology Showcase
In response to the oil and gas industry’s need to improve productivity while managing health, safety, and environmental (HSE) risks, Carnegie Mellon University’s National Robotics Engineering Center (NREC) developed and launched Sensabot, a mobile robot that it says can safely and cost-effectively inspect and monitor hazardous and remote production facilities.
The robot performs the same inspection and reporting tasks that humans do, such as monitoring the condition and performance of production equipment and areas, but without the risk associated with workers becoming exposed to hazardous conditions. The robot’s ability to operate in flammable and explosive conditions and its mobility distinguishes it from current energy industry inspection technology. It provides the monitoring and reporting capabilities of separate stationary instrumentation and also can respond to dynamic situational conditions.
The primary business incentive for using this robot is the alleviation of HSE risk, as well as the reduction of logistic and manpower costs associated with worker-performed inspections. Also, because the robot offers a variety of sensor capabilities, the facility operator can reduce the number of fixed sensors at the site, and the cost and risk associated with workers installing and maintaining these sensors. While this robot requires regular maintenance, it can be performed in safe and well-equipped workshops.
Robot Technology and Specifications
This robot is designed to meet Inter-national Electrotechnical Commission (IECEx) standards for electronic equipment operating in flammable and explosive environments. The robot design also complies with NACE MR0175/ISO 15156, the standard for materials used in H2S-containing environments in oil and gas production. The robot meets the American National Standards Institute safety standards for guided industrial vehicles and industry standard for human factors engineering guidelines.
The robot is a battery-powered machine controlled by a human operator through a remote Wi-Fi link and joysticks. The complete robot system also includes infrastructure components, such as a customized dumbwaiter elevator and a cog rail ladder for cost-effective integration into multilevel production facilities such as drilling rigs and refineries.