bluuebunny/crossref_metadata_2025 huggingface dataset:
Environmental Consideration Leads to Successful Decommissioning of FSO
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 157017, ’Decommissioning of an FSO Containing Hazardous Waste: A Successful Story,’ by Claude-Henri Chaîneau, Jean-Claude Bourguignon, Guillaume Goubard, and Pierre Bang, Total E&P; Philippe Jean, SPE, PJN Consulting; Benoit Lefebvre, SITA France; Tom Peter Blankestijn, Sea2Cradle; and Emmanuel Tambe Ayuk, SNH, prepared for the 2012 SPE/APPEA International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Perth, Australia, 11-13 September. The paper has not been peer reviewed.

Ship dismantling issues have never been as sensitive as they are now. In this context, the Rio del Rey partnership, represented by Total E&P Cameroun, planned the Serepca-1 (SR1) tanker’s end of life. SR1 was a Suezmax type oil tanker moored off the coast of Cameroon. The ship was a significant source of raw material and contained waste that could turn its dismantling into a health hazard and an environmental hazard. Various environmental surveys were made to identify hazardous materials and to produce the ship’s Green Passport. The end of life of any tanker has economic, environmental, and social implications.

Introduction

SR1 was a former oil tanker, built in 1974. In 1984, it was converted into a floating storage and offloading unit (FSO) and positioned in the Biafra bight, off the coast of the Republic of Cameroon. Its 14 tanks stored Kolé crude oil extracted from the Rio del Rey oil field. However, given the oil tanker’s age, the company decided to replace it. SR1’s oil storage activities ceased in May 2007, and it is in this context that a full decommissioning project was set up.

Given the large quantity of steel contained in the structure, an oil tanker constitutes a significant source of raw material. The elimination strategy selected, however, can turn such a tanker and the various polluting, toxic, or inflammable substances onboard into a health and environmental hazard. Several decontamination phases must be carried out in precise sequences before any dis-mantling operation, to prevent environ-mental and health risks. When one looks at the international situation, one sees that, during the last two dozen years, most of the world’s commercial ships and warships have been sent to developing countries to be dismantled in conditions damaging to the environment and to health. The evolution of environmental regulations in the member countries of the Organization for Economic Cooperation and Development (OECD) during the 1980s caused the cost of hazardous waste disposal operations to increase in industrialized countries. As a result, hazardous wastes have been exported to developing countries, where environ-mental regulations were less thorough. It is in reaction to this situation that the international community implemented the Basel Convention on the Control of Transboundary Movements of Hazardous Wastes and their Disposal.
Comments: 2014 Outlook
Authors: Donnelly John
Published: February 2015

Editor's column

Signs point to sustained strong oil prices this year, levels that will continue to support upstream unconventional projects in North America and elsewhere.

North Sea Brent and West Texas Intermediate (WTI) crude oil, the world’s two key benchmark prices, averaged around USD 108/bbl and USD 97/bbl, respectively, in 2013. And most price forecasts for 2014, which began emerging from analysts and investment houses in the fourth quarter, predict similar price levels in the new year. The wild card in that scenario, however, is the growth of non-OPEC supply and production levels from Libya and Iraq, which are difficult to anticipate. North American supply is expected to continue its upward swing, and significant increases in Kazakhstan are also forecast. Commercial production at Kashagan, Kazakhstan’s giant Caspian Sea oil field, is expected to begin in the first half of the year. The field was discovered in 2000, one of the largest finds in decades, but development has faced rising costs and numerous delays.

US crude oil production is expected to rise again this year. The US Energy Information Administration (EIA) says US crude output averaged 7.5 million BOPD in 2013 and will average 8.5 million BOPD in 2014. When US production hit 8 million BOPD in November, it was the highest monthly output level since 1988. The EIA believes that growth shows no signs of stopping, with US crude production forecast to come to a high of 9.6 million BOPD in 2016, a level not seen since 1970.

The EIA sees non-OPEC production growing from 54.2 million BOPD in 2013 to 55.9 million BOPD this year. Most of the non-OPEC production growth will be from US onshore tight oil formations and Canadian oil sands, with smaller increases from Africa, South America, and Asia. That will continue to put pressure on OPEC, which has watched its market share erode recently. OPEC countries are expected to produce 29.4 million BOPD this year, compared with an average of 30.3 million BOPD in 2013.

Oil prices are notoriously hard to predict. Some of the same analysts who forecasts strong prices this year predicted a sharp drop in oil prices in 2013, something that never happened. Nevertheless, there seems to be a consensus that Brent and WTI will remain near their current levels in the new year.

A survey of price forecasters published by Petroleum Intelligence Weekly in December showed most analysts seeing Brent in a USD 100-110/bbl range for the near year, and WTI at around USD 90-100/bbl. The survey of 10 analysts at consulting groups and investment banks shows Brent crude averaging USD 106/bbl for 2014, while the average for WTI is USD 97/bbl. Forecasters were optimistic that Libyan output would recover after months of disruption, and that a strengthening global economy would help absorb oil supply growth. JPT
Modeling Options for Drill-Cuttings Management
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164983, ’Modeling the Options for Managing Drill-Cuttings Piles on Decommissioning,’ Sean Hayes, SPE, Genesis, and Liz Galley, CNR International, prepared for the 2013 SPE European HSE Conference and Exhibition, London, 16-18 April. The paper has not been peer reviewed.

Advances in modeling techniques allow quantitative prediction of long-term trends in cuttings-pile characteristics and environmental risks, providing firm direction in mitigating risks. Modeling involving fluid dynamics, soil mechanics, scientifically verified 3D dispersion modeling, contaminant degradation, and seabed recovery was used in several scenarios: the extant pile, moving the pile across the seabed using suction pumps, backflush discharges related to retrieving the pile, and disturbance from remaining jacket footings ultimately falling into the pile after several hundred years.

Introduction

The Murchison platform is located in 156 m of water in the northern North Sea and is operated by CNR International. Drilling operations had been conducted at the field since the 1970s, ending in 2008. Discharges of drill cuttings and drilling mud have resulted in the formation of a drill-cuttings pile beneath the platform jacket structure. Between 1980 and 2000, oil-based muds were used and oil-contaminated discharges took place in line with normal permitted operations, and the cuttings pile now in place is consequently oil-contaminated. Fig. 1 shows the location of the Murchison platform and the local bathymetry, and Fig. 2 illustrates the jacket base.

The Convention for the Protection of the Marine Environment of the North- East Atlantic (OSPAR) Commission Recommendation 2006/5 sets out a management regimen for such oily-cuttings piles, depending largely on thresholds against which the level of pollution attributable to a historical cuttings pile may be measured in order to determine whether the level of pollution could be significant. An assessment of the Murchison pile was submitted to the commission in 2008 as part of the regulator’s implementation report, concluding that the Murchison pile did not exceed the relevant criteria and that it could be left to degrade by natural processes. For those piles that can be demonstrated to have characteristics below OSPAR thresholds, the recommendation states that no further action is required and that the cuttings piles may be left in situ to degrade naturally.

The Murchison field is in the process of being put forward for decommissioning, and the assessment made in 2008 regarding the rate of oil loss and the persistence footprint has been re-evaluated. By use of records of the discharges made from the platform, survey data from the Murchison cuttings pile, and industry data sources on the composition of drill-cuttings piles, a model of the existing pile has been constructed and used to understand the present condition and long-term fate of the pile.
Technology Focus: Drilling Technology (February 2010)
Authors: Menand Stephane
Published: February 2015

Technology Focus

Many discussions have taken place recently about the excessive nonproductive time (NPT) incurred in the drilling industry today and about the use of cutting-edge technology. From these discussions, it is believed that the drilling industry relies much more on cutting-edge technology than optimized-drilling practice to address downhole problems. Indeed, too many failures or dysfunctions still happen and are unexplained, even in supposedly simple wells, because of the lack of knowledge of what is happening downhole. Without having identified and understood the real cause of a given problem, one solution is to use a new technology that may overcome the problem without curing it. For economic reasons, cutting-edge technology often is used in complex and high-cost-environment drilling operations. For example, high-end rotary-steerable systems combined with downhole vibration measurements transmitted at high-speed along wired pipes enable achieving very complex and accurate drilling trajectories in geosteering. However, this accuracy is achieved as a result of the measurements but without necessarily understanding the drilling fundamentals and the physical phenomena involved. This method is a costly trial-and-error procedure. Indeed, in this complex-drilling operation, drillstring mechanics and hydraulics are very complicated, and physical models sometimes fail to predict and reproduce the actual drilling process. The solution to reduce NPT could be to use instrumentation and new technology in allegedly simple or basic wells to:    

Understand the new-technology function and performance

Validate the physical models (mechanics and hydraulics)

Improve fundamental drilling practices

Even though this high-end technology used in low-cost environments sounds contradictory, it should clarify our understanding of what is happening downhole to improve the overall drilling efficiency. Once fundamental drilling mechanics and processes are completely understood, one can go further in complex-drilling operations with the same technology and validated models. And as the proverb says, “Don’t put the cart before the horse!”

Drilling Technology additional reading available at OnePetro: www.onepetro.org

SPE 124142 • “Comprehensive Drilling Model Analyzes BHT Parameters” by A.W. Iyoho, SPE, Shell, et al.

SPE 123374 • “Statistical Method for Detection of Poor Hole Cleaning and Stuck Pipe” by Thor O. Gulsrud, SINTEF Petroleum Research, et al.

SPE 124631 • “Advanced Automatic Control for Dual-Gradient Drilling” by øyvind Breyholtz, International Research Institute of Stavanger, et al.

SPE 121752 • “Modeling the Effect of a Downhole Vibrator” by Ken Newman, NOV CTES, et al.
Using MPD To Drill Wells With Narrow Operating Windows: Pressure and Temperature Effects
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 119882, ’Drilling Wells With Narrow Operating Windows Applying the MPD Constant Bottom Hole Pressure Technology - How Much the Temperature and Pressure Affects the Operation's Design,’ by M. Arnone and P. Vieira, SPE, Weatherford International, originally prepared for the 2009 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 17-19 March. The paper has not been peer reviewed.

Narrow pore-/fracture-pressure-gradient margins translate to a real drilling-hazard scenario where a slight change in the bottomhole-pressure (BHP) conditions can lead to an increase in the nonproductive time (NPT) because of time spent in solving possible fluid losses or gas kicks. In specific and nonrare cases, deep formations with small gaps between pore and fracture pressure are undrillable with conventional drilling practices. Constant BHP (CBHP), one of a number of variants of managed-pressure drilling (MPD), enables staying in the window between pore- and fracture-pressure gradients. 

Introduction

The International Association of Drilling Contractors (IADC) recently has updated the definition of MPD. MPD is an adaptive drilling process used to precisely control the annular-pressure profile throughout the wellbore. The objectives are to ascertain the downhole-pressure-environment limits and to manage the annular-hydraulic-pressure profile accordingly. MPD is intended to avoid continuous influx of formation fluids to the surface. Any influx incidental to the operation will be contained safely by use of an appropriate process.

The IADC definition for MPD also includes some key technical notes:

The MPD process employs a collection of tools and techniques that may mitigate the risks and costs associated with drilling wells that have narrow downhole environmental limits by proactively managing the annular-hydraulic-pressure profile.

MPD may include control of backpressure, fluid density, fluid rheology, annular fluid level, circulating friction, and hole geometry, or combinations thereof.

MPD may allow faster corrective action to deal with observed pressure variations. The ability to control annular pressures dynamically facilitates drilling of what might otherwise be economically unattainable prospects.

At present, there are four recognized variations of MPD.

CBHP: Narrow pore- and fracture-pressure-gradient windows present a drilling hazard. When the hole is being drilled or circulated, the additional circulating friction to hydrostatic head can result in formation fracture. When circulation is ceased, the hydrostatic pressure is below the formation pore pressure. A kick/loss situation ensues, and NPT, lost-fluid cost, and health, safety, and environment (HSE) risk escalate. This variation is applicable to avoid changes in equivalent circulating density (ECD) by applying appropriate levels of surface backpressure, a technique that maintains CBHP during the complete drilling operation.
Multistation Analysis of MWD Magnetic Directional Surveys
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 125677, ’Minimum Requirements for Multi-Station Analysis of MWD Magnetic Directional Surveys,’ by Erik Nyrnes, SPE, StatoilHydro ASA; Torgeir Torkildsen, SPE, SINTEF Petroleum Research; and Harry Wilson, Baker Hughes, originally prepared for the 2009 SPE/IADC Middle East Drilling Technology Conference and Exhibition, Manama, Bahrain, 26-28 October. The paper has not been peer reviewed.

Multistation analysis (MSA) is a technique widely used in measurement-while-drilling (MWD) directional surveying to provide additional quality control and to correct for systematic errors. Although the potential of the method to enhance survey quality has been demonstrated, experience has shown that MSA can produce unstable solutions and poorly interpretable results. The full-length paper presents a set of fundamental requirements that have to be fulfilled to ensure the correct application of MSA. The requirements consist of a set of mathematical rules and corresponding acceptance limits. 

Introduction

MSA is a more-powerful survey-quality-evaluation method than conventional single-station calculations. It makes it possible to identify and quantify different types of systematic errors, providing greater proof of whether or not surveys meet specification. Where systematic errors of significant magnitude are identified, they can be corrected for. However, the ability of MSA to correct failed surveys and provide increased confidence that surveys meet their stated specification is limited by several factors. For example, only a limited number of systematic-error terms can be estimated accurately for a given set of survey data, this being dependent on factors such as the geometry of the wellbore, the number of survey stations, and the number of estimated error terms. In current common practice, it is not always clear how the application of MSA to a given survey log affects its status with respect to its own accuracy specification.

Improved accuracy may be claimed, but the link between MSA data manipulation and the error model that quantifies accuracy usually is not explicit.

In the full-length paper, a basic MSA methodology suitable for adoption across the industry is proposed. The methodology consists of a set of requirements and acceptance limits that have to be fulfilled when applying MSA. The requirements can be applied to any survey log to determine which error terms can be estimated validly. In addition, mechanisms are included to ensure that the random-noise level in the survey data is of tolerable magnitude. The requirements are easy to apply and straightforward to implement and, therefore, should be easily communicated throughout the survey industry.
Technology Focus: Offshore Facilities (February 2010)
Authors: Ball Ian G.
Published: February 2015

Technology Focus

In the relentless quest for reserves replacement, global upstream oil and gas operators continue their migration into deeper waters. The latest generation of subsea production facilities is widely applicable with confidence when specified correctly. However, selecting the optimum associated surface-processing facilities, and how best to link them to the subsea system, generally requires a more location-specific deliberation.

While field developments in established deepwater provinces such as the Gulf of Mexico, Brazil, and west Africa continue to expand, new deepwater regions such as in Southeast Asia and the Bay of Bengal off the east coast of India are being opened. However, even the well-established structural-design standards evolved by the industry for the Gulf of Mexico were recently shown by hurricanes Katrina and Rita to need a further overhaul in the way they are applied.

An unprecedented scarcity of equipment and resources suitable for deepwater drilling and construction also has driven up the unit costs and project durations sharply for deepwater developments in recent times.

All these factors have, collectively, encouraged the industry to seek and qualify an expanded and more flexible range of modular and integrated field-development solutions that can be optimized and applied more quickly in a reliable and cost-effective manner for the wider spectrum of deepwater challenges ahead. Among the most notable is the industry’s first floating-drilling, -production, -storage, and -offloading-based system that went into operation in deep water offshore west Africa during the past year.

These innovative floating and subsea deepwater solutions, when demonstrated by analyses and tests to be truly fit for purpose, are, however, only of meaningful value if upstream operators respond proactively with practical ways to apply them in the field quickly and confidently.

Offshore Facilities additional reading available at OnePetro: www.onepetro.org

OTC 19929 • “The Greater-Plutonio Riser Tower” by Daniel de la Cruz, BP, et al.

OTC 19857 • “Tahiti Spar as a Wet-Tree Concept” by P. Griffin, Chevron, et al.

SPE 124158 • “Northwest Hutton: Decommissioning the UK North Sea’s First Large Platform With a Fixed Steel Jacket: Topside Removal” by Chris R. Farrow, BP, et al.
Practical Solutions for Pressure-Transient Responses of Fractured Horizontal Wells in Unconventional Reservoirs
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 125043, ’Practical Solutions for Pressure-Transient Responses of Fractured Horizontal Wells in Unconventional Reservoirs,’ by M. Brown, SPE, and E. Ozkan, SPE, Colorado School of Mines; R. Raghavan, SPE, Phillips Petroleum Company (Retired); and H. Kazemi, SPE, Colorado School of Mines, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October.

An analytical trilinear-flow solution was developed to simulate the pressure-transient and production behavior of fractured horizontal wells in unconventional reservoirs. This solution provides an alternative to rigorous solutions, which can be cumbersome to evaluate. These solutions provide insight about and the conditions leading to these flow regimes.  Identifying these flow regimes is important to characterize unconventional reservoirs from pressure-transient tests.  

Introduction

Although it is possible to develop detailed analytical models to represent transient fluid flow toward a multiple-fractured horizontal well in tight unconventional reservoirs such as shale, the difficulties of these models are the increased computational requirements, the implicit functional relationships of key parameters, and the inconvenience of their use in iterative applications. Despite the complex interplay of flow among matrix, natural fractures, and hydraulic fractures, the key characteristics of flow convergence toward a multiple-fractured horizontal well may be preserved in a relatively simple, trilinear-flow model. The basis of the trilinear-flow model is that the productive lives of fractured horizontal wells in tight formations are dominated by linear-flow regimes.

Physical Model and Assumptions

For hydraulically fractured horizontal wells in unconventional reservoirs with microdarcy matrix permeabilities (such as shale), the contribution of the reservoir beyond the stimulated volume usually is negligible. Hydraulic fracturing also changes the stresses in the fracture-drainage area, which may create or rejuvenate natural fractures near the horizontal well. Under these conditions, flow convergence is mainly in the linear direction perpendicular to the surfaces of the hydraulic fractures, and, despite the complex interplay among matrix, natural fractures, and hydraulic fractures, a relatively simple, trilinear-flow model may represent the key characteristics of flow toward a multiple-fractured horizontal well.

The trilinear-flow model couples linear flows in three contiguous flow regions, as shown in Fig. 1: the outer reservoir beyond the tips of the hydraulic fractures, the inner reservoir between hydraulic fractures, and the hydraulic fracture. Each region can have distinct properties. The inner reservoir may be homogeneous or naturally fractured, and the hydraulic fractures may have finite conductivity.
Installation of a Damaged-Control-Line Replacement-Safety-Valve System in a North Sea Well
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 134500, ’A Case History: The Installation of a Damaged- Control-Line Replacement-Safety-Valve System in a North Sea Well,’ by T. Barratt, B. Goldsworthy, SPE, and S. Hamilton, Shell UK, and R. Lacy, SPE, M. Taylor, A. Ross, S. Mackie, SPE, E. Calzoncinth, S. Dennistoun, and J-L. Jacob, Weatherford International, prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. The paper has not been peer reviewed.

Well GA-03 on the Gannet platform in the UK sector of the North Sea developed a blockage in the safety-valve control line that rendered the existing tubing-retrievable subsurface safety valve (TRSSSV) inoperable. Also, the sealbores inside the valve were scarred and damaged badly enough that a conventional wireline safety valve would not seal. A method was examined that would allow replacement of the safety valve and control line without pulling the production tubing or making changes to the wellhead configuration.  

Introduction

Well GA-03 was spudded from the Gannet platform in 1994 and completed as a horizontal oil producer in 1995. In 1997, the water cut reached 95% and the well was shut in. In 2003, the well was reopened after a successful coiled-tubing (CT) water-shutoff intervention. In 2005, the water made production uneconomical again and a CT-drilled sidetrack of 257 ft completed with a slotted liner into the top of the reservoir was carried out.

In August 2007, the TRSSSV failed and was locked open. Many attempts were made to set an insert wireline-retrievable subsurface safety valve (WRSSSV), but the top seal stacks were damaged each time and it was not possible to get them to hold control-line pressure. This inability to obtain a pressure test indicated damage to the seal bores and to the inside of the tubing directly above and below the TRSSSV, although it was not possible to see the damage on caliper/video logs.

In December 2007, a 43-ft-long three-piece straddle assembly, including a 23/8-in. TRSSSV with a filter on the control-line port, was run across the existing locked-open TRSSSV. The packers were spaced out above and below the safety valve to be in what was assumed to be undamaged areas of tubing. The control-line pressure activated the TRSSSV by pressuring the whole annular volume of the straddle and, thus, the new TRSSSV through the filter. Although this system was unlikely to be a long-term solution, it was considered a good way to get the well back on stream in the short term. This safety-valve system functioned, despite losing control-line fluid for much of the time that it operated; this fluid loss required the well to be on its own fluid pump with frequent fluid top-ups, although once the well was flowing, the rate of losses reduced to near zero.
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.