bluuebunny/crossref_metadata_2025_split huggingface dataset:
Disconnect Tools Ease Removal of Upper Completion
Authors: JPT staff _ 
Published: February 2015

Young Technology Showcase
Intelligent completion systems have the ability to monitor and optimize reservoir performance in real time without mechanical intervention. Although such systems were introduced more than 15 years ago, the industry has only just begun to recognize and accept the numerous benefits derived from their implementation. Operators and service companies are now looking at new applications for intelligent completion technology including:
extended reach horizontal wells
marginally economic assets in which electric submersible pumps (ESPs) are required
regulatory compliance, such as nonfunctional subsurface safety valves replacements
However, these applications bring with them certain challenges. In ESP applications, ESP pumps require periodic retrieval for maintenance. With the high torque and drag in long horizontal wells, deploying intelligent completions on production tubing can become a challenge. When a workover is required to replace a nonfunctional subsurface safety valve, it can become more economical to leave the existing intelligent completion in place, and pull and replace only the upper tubing string including the subsurface safety valve.
How then can one reliably install intelligent completions in these applications? Intelligent completion disconnect tools help address these challenges.
Intelligent Completion Disconnect Tools
Recently introduced disconnect tools for intelligent completion applications by Halliburton facilitate the removal of the upper completion from the lower completion without any destructive or mechanical intervention. This leaves the intelligent completion lower assemblies, such as packers, interval control valves (ICVs), and permanent downhole gauges in the wellbore undisturbed.
Intelligent completions require hydraulic and electrical umbilicals to monitor and control the gauges and ICVs in the wellbore. Besides providing tubing-to-annulus integrity, disconnect tools must also reliably disconnect (demate) and reconnect (wet mate) the umbilicals without affecting the functionality of the downhole intelligent completion equipment. Two variants of the disconnect tool are the hydraulic and the electro-hydraulic. The electro-hydraulic provides the ability to multi drop gauges on a single I-wire and hydraulically actuate ICVs in the lower intelligent completion.
Design
These disconnect tools are exclusively designed for intelligent completion applications. The tool comprises two halves: the receptacle and the disconnect sub (Fig. 1). When the two halves are wet mated, hydraulic and electrical continuity is achieved from the surface down to the ICVs and gauges.
Management System Approach Aims To Meet Human Rights Expectations
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 164979, ’Management Systems Approach to Managing Human Rights Issues,’ by Tam Nguyen, Chevron, Bert Fokkema, Shell, Julie Vallat, Total, and Roper Cleland, IPIECA, prepared for the 2013 SPE European HSE Conference and Exhibition, London, 16-18 April. The paper has not been peer reviewed.
A range of external expectations exists for companies to demonstrate how they respect human rights, including having business processes in place to prevent or mitigate human rights issues caused by the company’s projects or operations. The International Petroleum Industry Environmental Conservation Association (IPIECA) has responded to the emergence of external guidelines in connection to implementing human rights due diligence by improving existing management systems and processes.
Background
United Nations Guiding Principles on Business and Human Rights. The United Nations Guiding Principles on Business and Human Rights were developed through an iterative process spanning 6 years and involving extensive stakeholder consultation.
In the first stage of the work, John Ruggie, United Nations special representative to the secretary-general, conducted 3 years of research to develop the global Protect, Respect, and Remedy Framework on business and human rights. Ruggie developed the framework to help clarify the distinct roles of states and businesses in human rights. It rests on three interdependent pillars—the state duty to protect against human rights abuses by third parties through regulation and legislation; the corporate responsibility to respect human rights through due diligence; and the need for citizens to have access to effective remedy, both judicial and nonjudicial.
The United Nations Human Rights Council endorsed the framework in 2008. Upon endorsement, Ruggie established the United Nations Guiding Principles. The principles supplement the framework by outlining how governments should meet their duties and how companies should demonstrate their responsibilities.
IPIECA’s Business and Human Rights Initiative. IPIECA launched a 3-year business and human rights project that leverages the collective experience and practical knowledge of its members. The objectives of the project are to
Support the organizational capability of IPIECA members in two focus areas, company due diligence and community-level grievance mechanisms
Serve as the authoritative reference body for the oil and gas industry on business and human rights issues, including the United Nations Guiding Principles on Business and Human Rights and other relevant external guidelines
Inducing an Earthquake by Injecting Water in a Gas Field
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166430, ’Inducing Earthquake by Injecting Water in a Gas Field: Water- Weakening Effect,’ by Axel-Pierre Bois and Mehrdokht Mohajerani, CurisTec; Niek Dousi, SGS-Horizon; and Stijn Harms, Vermilion Energy, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed.
On 26 November 2009, a 2.8-magnitude earthquake (henceforth referred to in this paper as the De Hoeve tremor) occurred in southwestern Friesland in the Netherlands at an approximate depth of 2 km. This relatively shallow depth indicated that the event was induced. The closest mining activities were believed to be in the Weststellingwerf field. A study was required to determine the origin of the tremor, evaluate if it could be followed by other tremors in the future, and estimate its magnitude.
Introduction
The tremor’s epicenter was identified by the KNMI (Koninklijk Nederlands Meteorologisch Instituut: Royal Netherlands Meteorological Institute) (Fig. 1). Three wells are located near the epicenter: Weststellingwerf-01 (WSF-01), Noordwolde-01 (NWD-01), and De Hoeve-01 (DHV-01). They all are producing from formations at a depth of approximately 2 km.
Well WSF-01 was a gas producer between 1998 and 2004; cold-water injection started in 2008 with no tremor reported during the gas-production phase.
Well NWD-01 is immediately outside of the epicenter perimeter. It was producing gas at the time of the event, with no tremor measured before November 2009 and none after.
Well DHV-01 is located in the middle of the estimated epicenter area, but had not been drilled at the time of the event.
The observed tremor, because of its shallow depth, was assumed to be induced instead of having occurred naturally. It was attributed by KNMI to displacements along the Weststellingwerf fault because the seismograms were in agreement with a normal west/eaststriking fault. It was thus necessary to identify which mechanism was at the origin of the fault movement, to investigate whether an earthquake could occur in the future, and to determine the magnitude of the event.
Five mechanisms were studied:
Salt dissolution
Reservoir depletion during gas production
Reservoir repressurization caused by water injection
Temperature variations caused by cold-water injection
Fault weakening caused by lubrication or annihilation of capillary pressure during water injection
However, salt dissolution during water injection was quickly discarded as being at the origin of the tremor because the reservoir intervals do not contain halite. Carbonate dissolution was not pronounced and could not explain fault weakening caused by water injection, either.
Validation of a Biological-Monitoring Design in Highly Diverse Tropical Forests
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 165632, ’Validation of a Biological-Monitoring Design in Highly Diverse Tropical Forests,’ by K. Caro, E. Enriquez, E. Juscamayta, E. Oyague, and J. Cabrera, Knight Piesold, and C. Chung, C. Ahumada, A. Watson, and C. Videla, Repsol, prepared for the 2013 SPE Latin American and Caribbean Health, Safety, Social Responsibility, and Environment Conference, Lima, Peru, 26-27 June. The paper has not been peer reviewed.
Biological-monitoring programs provide data for decision making and to ensure the protection of resources. However, in tropical ecosystems that are home to most of the planet’s biodiversity, these programs need to be improved in design and implementation. Block 57 in the Amazon rain forest of southern Peru is an ecosystem with limited information. A systematic biological-monitoring program was designed on the basis of a gradient of disturbance caused by clearing an area.
Introduction
Oil exploration in Block 57 involves clearing small forest areas during installation of drilling platforms. One of the consequences of this clearing is an increase of edges and the presence of habitats with early successional stages. An edge is defined as a transition zone between two adjacent ecosystems or vegetation communities. In these edges, deleterious effects may be generated.
A biological-monitoring plan has been designed as part of an environmental- management plan to understand the effect that the changes in the habitat associated with the exploratory wells within the primary cloud forests have on the abundance, richness, and diversity of the local flora and fauna.
Study Area
Block 57 is on the southern Amazon plain and the first foothills of the eastern slope of the Peruvian tropical Andes Mountains (Fig. 1). This is one of the areas with the greatest precipitation and highest temperatures and relative humidity in Peru. At several locations, total annual precipitation exceeds 3000 mm. Relative humidity exceeds 90% in the mornings, and temperatures commonly exceed 37°C in the afternoons during the dry season when the sky is clear.
The study area is in the buffer zones of the Otishi National Park and the Ashaninka and Machiguenga Community Reserves. It is predominantly hilly, with mountainous areas in the western sector and terrace areas near the Tambo and Urubamba rivers. Floral composition in the study area is very heterogeneous with different densities. Palm trees are another representative and varied group in these forests, sometimes rising above the canopy.
The work design includes three platforms in Block 57—Kinteroni BX, Mapi LX, and Mashira GX. This study includes the results of monitoring conducted on the surroundings of the Kinteroni BX exploration platform, also known as Sagari (Fig. 2).
Overview: Completions Today (September 2005)
Authors: Gomersall Sam 
Published: February 2015

High oil prices are good for the industry. Producers start to focus on value instead of cost. When they do this, the service and supply sector is better able to help by starting to understand the technical and business challenges and creating innovative solutions. These solutions include the development or application of new technologies, creative system solutions, and field-development plans that move the industry forward.
One challenge is ensuring that the service sector experiences benefit from higher oil prices because, increasingly, that is where the expertise, technology, and R&D investment exists. Anything that stifles the growth of the service sector, especially the innovative smaller companies, will become a problem in the future.
However, historically, it usually has been low oil prices that precipitate the most significant changes in our industry. The challenge now is to use the stimulus of high oil prices and value focus to implement new technologies and increase industry collaboration rather than using high oil prices as the cushion to avoid doing anything different.
It is our ability to take significant steps forward when the oil price is high that deter-mines who will be successful and who will not.
There are many reasons for not implementing new technology. At an individual level, they include lack of awareness, lack of expertise, lack of time, and lack of personal stimulus. In the completions area, it is our responsibility to continue to develop and apply new technology, overcoming these barriers and using the high oil price as a driver for change.
The industry is schizophrenic when it comes to collaboration: on the one hand, sometimes we work close together (e.g., joint-venture partnerships), and we share learning through organizations such as SPE; yet on the other hand, both producers and service companies regard knowledge as a differentiator, to be kept away from other companies. The future success of companies will, I believe, require more collaboration and less isolation. Companies and individuals who are team focused and who collaborate across traditional boundaries will be most successful. So as engineers, look outside your organization, share what you have learned, and learn what others are doing.
Available from the SPE eLibrary: www.spe.org
SPE 92024 - “Milling of Isolation Valve With Wireline-Conveyed Technology,” by Krüger, C., SPE, Welltec, et al.
SPE 92392 - “Unique ‘Through-Tubing’ Completions Maximize Production and Flexibility,” by Johnson, M.O., BP plc, et al.
SPE 93920 - “Performance of Downhole-Separation Technology and Its Relationship to Geologic Conditions,” by Veil, J.A., SPE, Argonne Natl. Laboratory, et al.
Available from the OTC Library: www.otcnet.org
OTC 17113 - “Completion Technology on Troll—Innovation and Simplicity,” by Haaland, A., Norsk Hydro ASA, et al.
Quantifying Petrophysical Uncertainties
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 93125, "Quantifying Petrophysical Uncertainties," by S.J. Adams, SPE, WellEval.com Ltd., prepared for the 2005 Asia Pacific Oil & Gas Conference and Exhibition, Jakarta, 5-7 April.
Typical petrophysical deliverables for volumetric and modeling purposes are net reservoir, porosity, permeability, water saturation, and contact locations. These data usually are provided without quantitative determination of their uncertainties. This paper highlights the use of Monte Carlo simulation to derive uncertainties. The technique works with different interpretation models, which commonly is not done. The largest source of uncertainty in petrophysical interpretation may be the interpretation model itself.

Introduction
Petrophysical evaluations are carried out for many purposes, including operational decision making, volume-in-place estimation, and reservoir modeling. In all cases, the uncertainty in the deliverables of net reservoir, porosity, permeability, water saturation, and contact locations is critical. However, these data usually are provided without quantitative determination of their uncertainties.
Given the many possible interpretation models for all the different petrophysical deliverables, this paper used only the most basic petrophysical deliverable, porosity, to illustrate the relationship between uncertainty and the log-interpretation model selected. Verification of log porosity with an independent measure, such as core porosity, also can provide quantitative uncertainties, allowing comparison with the log-derived uncertainties.
Screening Methodology for Downhole Sand-Control Selection
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 88493, "Screening Methodology for Downhole Sand-Control Selection," by Chris Farrow, SPE, Helix RDS, and David Munro and Thomas McCarthy, Woodside Energy Ltd., prepared for the 2004 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 18-20 October.
The sand-management strategy for existing Northwest Shelf (NWS) fields offshore Australia involves reactive down-hole sand control in the event sand is produced above acceptable limits. Sand-face completions for new wells consider well and system risks during the life of the development. A screening method was developed to evaluate and rank available sand-control techniques for NWS conditions. Published criteria were used in a systematic manner, allowing a consistent, balanced, and transparent view of benefits and risks across the different system aspects.

Introduction
The NWS gas/condensate fields (North Rankin, Goodwyn, Perseus, and Echo-Yodel) are approximately 135 km offshore from Dampier, Australia. Typically, these fields were developed without downhole sand control or specific topside sand-handling equipment. Considerable benefits have been realized in terms of development costs and production capacity as a result, with minimal sand production observed to date. However, there is uncertainty about future sand production as reservoirs deplete or water breakthrough occurs.
Woodside formed an integrated sand team with the specific aim to protect against the possible effects of sand. The team developed a sand-management strategy as follows.
- Manage current (low) levels of sanding by well management (including best practices for sand monitoring, drawdown, and bean up) and assess topside desanding options.
- Develop a downhole plan for key existing wells. Activate this plan on a reactive basis if sand production becomes a problem.
- Build system robustness against the risk of sand by considering the installation of downhole sand control in new wells.
To support this strategy, a systematic approach to ranking available sand-control options (for both remedial and new-field developments) was developed and applied.
Sand Management on the Lunskoye High-Gas-Rate Platform: Quantitative Risk Assessment
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 112099, "Applying Sand-Management Process on the Lunskoye High-Gas-Rate Platform Using Quantitative Risk Assessment," by M.C. Gunningham, SPE, Sakhalin Energy Investment Company; M.A. Addis, SPE, Shell; and J.A. Hother, SPE, Proneta UK, prepared for the 2008 SPE Intelligent Energy Conference and Exhibition, Amsterdam, 25-27 February. The paper has not been peer reviewed.
Quantitative risk assessment (QRA) was applied to sand management in the Lunskoye field to minimize risk of failure while maximizing production, reducing cost, and safeguarding reserves. Lunskoye is a high-rate gas development offshore Sakhalin Island. This work has reduced the project risk exposure significantly, while reducing well-completion costs and safeguarding production in the long term.

Introduction
The Sakhalin Phase-2 development comprises two new offshore platforms, one on the Lunskoye field and the second on the Piltun field. The Phase-2 development also includes changing the existing Astokh platform to a year-round production operation. These platforms will be linked to an oil terminal and a liquefied-natural-gas (LNG) plant 800 km away on the southern edge of Sakhalin Island. More than 90% of the gas for the LNG plant will be supplied by the Lunskoye field (Fig. 1).
The Lunskoye field is in 48 m of water in the Sea of Okhotsk, east of Sakhalin Island. The potential of sand production disrupting gas production and LNG delivery was minimized in the design stage of the project. The full-length paper details a QRA based on the as-built Lunskoye-A facilities and updated well and completion designs. The aim was to reduce residual risks further by identifying and quantifying the critical failure modes and identifying appropriate mitigating measures by use of a systematic rigorous methodology based on sound principles, which is able to provide implementable results.

Completion Design and Predicted Sand Production
This QRA of the Lunskoye-A wells and production facilities focused specifically on failure modes resulting from sand production. Sand production occurs when the reservoir effective stresses exceed the strength of the sandstone, resulting in rock failure and disaggregation, during which sand grains become detached from the sandstone. The effective stress in a reservoir increases during depletion, causing the weaker sandstones to fail, followed by the failure of successively stronger sands as depletion continues. If the disaggregated sand is transported to the facilities in the gas and liquid stream, it will result in erosion of the flowlines and will settle in areas of low flow velocities, leading to plugging. If the sand is not transported out of the wellbore and remains in the well, the completion interval will gradually "sand up" and production will decline, requiring a workover and a cleanout to restore productivity.