bluuebunny/crossref_metadata_2025_split huggingface dataset:
Oxidation of Mercaptan, Dimethyl Sulfide in Aqueous Waste
Authors: Sheeran Kenneth , Murray Michael , Lehane Jonathan , O'Flaherty Tadg 
Published: February 2015

Technology Update
Tert-butyl mercaptan (TBM) and dimethyl sulfide (DMS) are odorous compounds added to natural gas to warn of a gas leakage so that an alarm can be activated. In a storage project for gas produced from platforms offshore Ireland, TBM and DMS were expected to be present in a low-volume aqueous waste stream. Project developers designed an economical process to treat these compounds so that the stream could be accepted at a water treatment facility. Several permutations of plant design and disposal routes were evaluated, and an advanced oxidation process trial was found to yield a straightforward process for mercaptan treatment.
Background
The business model of seasonal gas storage is to inject natural gas into an underground reservoir when gas is relatively cheap (summertime) and withdrawing the gas when the price is higher (wintertime). In this project, the injected gas is odorized with TBM and DMS to 4.7 ppmv and 1.3 ppmv, respectively. The proposed offshore storage reservoir is tied to the shore terminal by a 34-mile pipeline.
To inhibit hydrate formation, monoethylene glycol (MEG) and methanol (MeOH) will be injected into the withdrawn gas. The gas exiting the reservoir is expected to be water saturated and water will condense because of the loss of pressure as the gas travels up the wellbores and through the pipeline. At the shore terminal, the aqueous MEG/MeOH will be separated from the gas stream for recovery. The aqueous waste stream must be treated before disposal. Because the injected gas will contain TBM/DMS, the withdrawn gas and waste stream will contain these compounds, too. The waste stream will also contain trace amounts of native petroleum species (alkanes, aromatics, ammonia, etc).
The waste stream is expected to have relatively low-volume flow rates on the order of 1 m3/d to 10 m3/d. This flow rate is seasonal and can change daily, even within the season, in line with fluctuating customer nominations. There is also considerable uncertainty at the upper flow limit, which makes it difficult to size the plant throughput.
Technology Focus: Offshore Facilities (February 2012)
Authors: Ball Ian G. 
Published: February 2015

Technology Focus
Last year, we reviewed some of the more-prominent examples of how the industry continues to respond to the need for safe and cost-effective production facilities in ever-more-challenging environments. We also highlighted the increasingly important role that constructive collaboration can play in facilitating the desired outcomes for all parties.
This year, we illustrate how this same theme of constructive collaboration has been applied effectively at the other end of an offshore facility’s life span, in the major decommissioning program for the Frigg field. Most of us are very familiar with the term offshore hookup, but soon we may become equally familiar with what offshore “hookdown” really involves.
We also take a look at an approach for safely extending the useful life of aging offshore-production infrastructure, in locations where the subsea tieback of new fields warrants the associated investment.
Our focus is not entirely on end-of-life scenarios though. New offshore-platform concepts continue to evolve to suit the changing needs of operators. Some of these aim to offer the reduced well cost of fixed structures with the redeployment advantages offered by floating structures.
One of the most challenging new frontiers for the offshore industry and for society at large is the Arctic region. More specifically, it is development of underwater hydrocarbons where the presence of ice affects the nature of the development.
Moving into any new frontier first requires gathering sufficient environmental data to be able to predict quantitatively the character and envelope of conditions at that location throughout the field’s production lifetime. We take a look at how these issues are being addressed in the specific case of the proposed Shtokman-field floating production facility.
As we return for this annual JPT Focus on the technology associated with offshore oil/gas facilities, it is timely to mention the launch of the new SPE magazine Oil and Gas Facilities, primarily geared toward the whole offshore-facilities sector. This effort represents a significant initiative to broaden the appeal and relevance of SPE to the wider oil/gas community, and any feedback that you may have in this regard would be welcomed warmly.
Recommended additional reading at OnePetro: www.onepetro.org.
OTC 21708 Decommissioning of Frigg and MCP01—A Contractor View by T. Gram, Aker Solutions, et al.
OTC 22505 The First Dry-Tree Semisubmersible Drilling and Production Platform Sold by Roberto Noce, Moss Maritime, et al.
OTC 22078 Design Considerations for an Arctic Intervention Vessel by Tor Einar Berg, Marintek, et al.
Frigg Cessation Project
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 148626, ’The Frigg Cessation Project,’ by Jean-Claude Berger, Total S.A., prepared for the 2011 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 6-8 September. The paper has not been peer reviewed.
The Frigg Cessation Project included the removal of six topsides, three steel jackets, and sealines with an estimated weight of 87 000 t. The project is unique because the field straddles the border between Norway and the UK. Both Norwegian and British statutes apply, depending on the location of the platforms. The main execution phases are described, from the offshore latch down, removal, and transportation to the onshore disposal of the installations.
Introduction
The Frigg field was a natural-gas reservoir on the North Sea continental shelf. The field was discovered in June 1971 in the Norwegian Block 25/1. In April 1972, gas was encountered in the neighboring UK Block 10/1. In July 1973, the Frigg licensees signed a unitization agreement regulating the split of the reserves between Norway and the UK. In May 1976, the Norwegian and British governments signed an agreement, known as the Frigg Treaty, under which Elf Norge (now Total E&P Norge) was defined as the operator of the Frigg field while Total Oil Marine (now Total E&P UK) was defined as operator of the gas-export system.
Development of the Frigg field took place between 1973 and 1977 and consisted of five platforms (Fig. 1). Three platforms were in UK water—one drilling-and-production platform (CDP1), a treatment platform (TP1), and a living-quarters platform (QP). The two other installations were in the Norwegian sector—one drilling-and-production platform (DP2) and one treatment-and-compression platform (TCP2).
Three of the platforms, TP1, QP, and TCP2 were linked permanently and formed what was known as the Frigg Central Complex. Three of the platforms—CDP1, TP1, and TCP2—and the intermediate platform MCP01 had concrete gravity-base substructures; QP and DP2 had steel-jacket substructures. The topsides of all platforms consisted of steel decks supporting several modules and pieces of equipment. First gas was produced from Frigg to St. Fergus in September 1977. In October 2004, the Frigg reservoir was finally shut in, having delivered approximately 192×109 std m3 of gas to the UK domestic market.
Pressure-Transient and Production-Data Analysis of an Unconsolidated Formation
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 147506, ’Pressure-Transient and Production-Data Analysis of a Horizontal Well in an Unconsolidated Formation in Frade, Brazil,’ by Yan Pan, SPE, Russ Ewy, SPE, Don Ringe, SPE, Medhat M. Kamal, SPE, Ralph Affinito, SPE, and Oluwole Sotunde, SPE, Chevron, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed.
Frade Asset is a medium-heavy-oil field in the northern Campos basin, approximately 75 miles offshore Rio de Janeiro in 3,500-ft water depth. The structure is a low-relief anticline with two main fault blocks consisting of four stacked unconsolidated reservoirs. The field produces from nine horizontal oil wells with three vertical water-injection wells to maintain reservoir pressure. Continuous well monitoring and reservoir characterization are key to cost-efficient development in this deepwater subsea field.
Introduction
The development strategy for the field includes horizontal production wells and deviated injection wells to maintain reservoir pressure. The asset-management team realized the challenges of this particular field and made the decision to install permanent downhole gauges in every production and injection well drilled, with a reservoir-surveillance plan in place to monitor well and reservoir performance.
Active reservoir surveillance enabled engineers to make sound and quick operating decisions, such as shutting in wells, changing chokes, or planning well interventions on the basis of dynamic data collected continuously at wells. It also provided real-time information for improved reservoir characterization, model forecasts, and optimized development plans. Because data stream in continuously, the cycle from data collection to updating reservoir models to forecasting field performance to optimizing development could be shortened.
Example Well: Producer 2
Well Producer 2 is in the upthrown fault block, as shown in Fig. 1, and had an original reservoir pressure of 3,079 psia and a reservoir temperature of 110°F. The net pay thickness is approximately 42 m, and the horizontal well was drilled 30 m above the sealing bottom of the reservoir. The well trajectory was parallel to the fault to the southwest and to the axial fairway edge to the northeast. The well was completed with an openhole gravel pack, and the total completion length was 507 m. The permanent downhole gauge was installed above the top of the gravel-pack completion.
Mechanical Extrusion Offers Advantages Over Ball Activation for Downhole Tools
Authors: Churchill Mike 
Published: February 2015

Technology Update
One of the most innovative recent advances in downhole drilling tool activation has been the introduction of mechanical extrusion technology, incorporating the use of rigid metal darts to improve the cycling and control of a variety of processes and devices. Increasingly, operators are recognizing mechanical extrusion by means of dart activation as a time-, cost-, and labor-saving alternative to traditional ball activation methods.
For example, conventional cycling of drilling bypass valves has used a polymer extrusion process that relies on balls as the activation device. However, Churchill Drilling Tools has developed an effective and accurate mechanical extrusion method that uses a dart-based valve. The system can perform activations up to five times faster than polymer methods.
The company’s MX (mechanical extrusion) system allows the use of rigid Smart Darts for multicycle control and exploits their robustness and resilience at high pressures and temperatures (up to 660°F) to deliver greater operating speed, reliability, and performance. The system’s unique feature is its two configurable shearing modes, which solves reliability and power delivery problems. It requires a radius as small as 0.0075 in. for power transmission, thereby making implementation extremely compact.
With the ability to control and power three or more tools independently, users eliminate the conventional inner diameter (ID) and obstruction conflicts between different tools in a string. This has implications for mono-cycling ball and shear systems, which commonly obstruct the bore after use. These can be turned into multicycling, nonobstructive, and multi-tool systems. The system can also enhance multicycling ball-activated tools that are based on polymer extrusion by improving performance and delivering greater multitool compatibility and interoperability.
The system allows the mechanical extrusion to be delivered in a range of settings to suit the specific cycle application. With a variety of latching, sealing, and flow path geometries, as well as the adjustable shear mode ratings, this element of the system provides a tangible change in string design and program implementation. For example, in bypass valve implementation, users can cover multiple flow path contingencies with a single valve in hole and choose from the range of darts to establish the optimal setting for the situation encountered.
The system advances the capability of simple hydromechanical control and its power and reliability benefits into areas that previously needed more complex electronic systems. Being mechanical, it is not subject to the same high pressure and high temperature limits that affect electronics and electrical components.
Smart Darts enable a multicycle circulating sub (circ sub) tool to deliver a reliable and versatile bypass on demand. Whatever the drilling application, whether planned or a contingency, the system enables a rapid and reliable switching to the optimal flow path configuration.
Shopping for New Ideas Outside the Oil Business
Authors: Rassenfoss Stephen 
Published: February 2015

Technology Transfer
Jason Norman’s search for components for an automated system to manage drilling fluids often begins with an online search.
The senior drilling engineer for Apache Corporation has identified many possible inline instruments to choose from, mostly from companies outside the oil and gas industry. Machines used to test the thickness of yogurt or the water levels in olive oil have been considered to measure the flow rate, density, water cut, viscosity, and the size of particles in drilling mud.
It is part of Apache’s program to create an automated drilling system that is faster, safer, and more dependable, using constant measurement to control every aspect of drilling. To do this cost-effectively for onshore rigs “this needs to be off-the-shelf equipment. There are no inventions here,” Norman said.
He and other members of the Apache automation team, who are working on everything from equipment control systems to programming, are taking advantage of the fact that manufacturers have already created automatic control technology that can be adapted to run a drilling rig like an automated factory.
This ambitious project is an example of how, when oil and gas exploration and service companies face new challenges, often the shortest path to a solution is to adapt other people’s technology.
This marketplace of new ideas was on display last fall at the Innovation Showcase put on at the Oil & Gas Innovation Center, where 24 companies pitched what they could do to a conference room full of oil company technology experts on Anadarko’s campus in The Woodlands, near Houston.
For young, innovative companies the oil industry’s appetite for high performance, and its ability to pay for it, is a draw at a time when budgets are shrinking for the defense and space programs that often fund early-stage technology development.
For oil explorers, the rush to find and develop unconventional reservoirs is just one of the challenges that reward innovators. The quickest way to do that is to reply on other people’s research and development.
When John Barratt, the founder and chief executive officer for the Oil & Gas Innovation Center looks at the traffic on the company’s website he sees a pattern: Big independents, such as conference sponsor Anadarko, are most likely to be reading its profiles of promising young companies. “We are able to tell who is using the [web] site and I can tell you the heaviest users are independents,” he said.
Technology Focus: Well Testing (February 2013)
Authors: Guzman-Garcia Angel G. 
Published: February 2015

Technology Focus
The times they are a-changin’, Bob Dylan sang in the mid-1960s. And it seems to be the case in our industry today. With the never-ending search for new sources of hydrocarbons in more-complex environments, the application of old technologies has not been satisfactory to help us fully realize the new exploration opportunities. As the oil industry endeavors to extract hydrocarbons from fields where, only a few decades ago, it seemed impossible, engineers and scientists are tasked with developing ideas to gain an understanding of the dynamic behavior of the reservoirs, sometimes requiring redundant information. Creativity and ingenuity are called upon when facing challenging projects. Both are particularly necessary when one is trying to extract as much information as possible by the clever integration of multiple groups within an organization and manipulation of complementary data sets.
Despite the difficulties encountered in unconventional plays or in tight carbonates that normally require stimulation, along with patience and long-term commitment, the application of sound engineering principles has opened new areas around the world that, until recently, were perceived as not being economical. Two of the key parameters required for full exploitation of a hydrocarbon-bearing field—rock permeability and reservoir pressure—are probably the most elusive to determine in the exploration phase, particularly so in unconventional plays. Hence, any technique that decreases the uncertainty in those estimates is a new valuable tool to the engineers involved in the exploration of new frontiers. Once the size and properties of the container have been evaluated, knowledge of the fluid properties is required to under-stand the flow characteristics.
In the early stages of developing a field, on the other hand, engineers and geoscientists continue to integrate as many data sets as possible to quantify the volume of hydrocarbons that may be produced. The well-test data, however, confirm whether the hydrocarbons are producible. With this information, field development can start in earnest. The integration of the static and dynamic data then provides encouragement to develop a field.
The three articles chosen are good examples of data integration to understand a field or the clever use of well-test data to solve a specific problem. The interested reader should also check the three alternative articles, as well as other articles available in the OnePetro library (www.onepetro.org).
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 159126 Reservoir-Connectivity Analysis Using Long-Term Interference Testing in a Waterflood Pilot in the Carbonate Marrat Formation of the Greater Burgan Field, Kuwait by Naz Gazi, Kuwait Oil Company, et al.
SPE 159503 Sampling While Drilling: An Emerging Technology by Steven Villareal, Schlumberger, et al.
SPE 159680 Investigation of Thermal Well-Test Analysis for Horizontal Wells in SAGD Process by Ashkan Jahanbani Ghahfarokhi, Norwegian University of Science and Technology, et al.
Controlled-Electrolytic-Metallics Completion Devices Combine Strength With Dissolution
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 153428, ’Controlled Electrolytic Metallics—An Interventionless Nanostructured Platform,’ by Bobby J. Salinas, SPE, Zhiyue Xu, SPE, Gaurav Agrawal, SPE, and Bennett Richard, SPE, Baker Hughes, prepared for the 2012 SPE International Oilfield Nanotechnology Conference and Exhibition, Noordwijk, The Netherlands, 12-14 June. The paper has not been peer reviewed.
Experiments on oil/water nanoparticle flow behavior in confined clay nanochannels were conducted with molecular-dynamics simulations. Three sizes of nanochannels and different numbers of nanoparticles were considered. The results show that the pressure to drive the oil/water binary mixture through a periodic confined channel increases dramatically with the reduction of the channel size. In the absence of nanoparticles, the pressure increases with the propelled displacement. An opposite behavior is observed in the oil/water system mixed with a small amount of nanoparticles: The pressure decreases with the increase of the displacement. The findings from molecular-dynamics simulations may elucidate the role of nanoparticles in the transport of oil in nanoscale porous media.
Introduction
One of the more promising applications of nanotechnology in the field of oil and gas, in particular for enhanced oil recovery and drilling, is the creation of a new generation of fluids. Nanofluids are a class of fluids engineered by dispersing nanoparticles (nanofibers, nanotubes, nanowires, or nanodrops) in base fluids. Nanofluids were first recognized because of their thermal properties.
The most commonly studied nanoparticles for enhanced oil recovery are the spherical silica nanoparticles with a diameter in the range of several to tens of nanometers. Functionalized nanoparticles can form a highly stable emulsion to determine the oil-saturation situation, improve the oil-flow mechanism, and identify the location of bypassed oil. Al-though the exact interface mechanisms are still unclear, it is generally expected that silica nanoparticles will also reduce the surface tension between oil and rock and enhance the depletion of oil from porous media. Before full-scale deployment of silica nanoparticles occurs, many issues remain to be resolved, such as how the particles behave in a reservoir and how to design the appropriate silica nanoparticles.
This study focused on the fundamental understanding of the role of silica nanoparticles in the oil/water binary mixture in a confined nanochannel.
Structure and Simulation Details
Rocks that are rich in kaolinite are known as kaolin clay. Kaolinite has the chemical composition Al4Si4O10(OH)8 (Fig. 1). Kaolinite is a layer clay with neutral charge, and the asymmetric structure allows the formation of hydrogen bonds between consecutive layers.