bluuebunny/crossref_metadata_2025 huggingface dataset:
Distributed Acoustic Sensing for Hydraulic- Fracturing Monitoring and Diagnostics
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 140561, ’First Downhole Application of Distributed Acoustic Sensing for Hydraulic-Fracturing Monitoring and Diagnostics,’ by M.M. Molenaar, SPE, Shell; D.J. Hill, QinetiQ OptaSense; and P. Webster, E. Fidan, SPE, and B. Birch, SPE, Shell, prepared for the 2011 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, 24-26 January. The paper has not been peer reviewed.

Distributed acoustic sensing (DAS) is a fiber-optic technology that enables detecting, discriminating, and locating acoustic events with a standard telecom single-mode fiber several kilometers in length. Use of a combination of the measurement of backscattered light and advanced signal processing enables the DAS interrogator system to segregate the fiber into an array of individual “microphones.” One downhole application of DAS is monitoring hydraulic fracturing of tight-sand and shale-gas reservoirs.

Introduction

Fracture monitoring is key to understanding and optimizing hydraulic-fracturing treatments. The diagnostics focus on determining stimulation effects such as fracture geometry, proppant placement in the fracture, and fracture conductivity.

Historically, completion engineers have been limited to the use of surface wellhead rates and pressures, and occasionally downhole pressures, as their main sources of real-time information. To address such limitations, Shell Canada has been deploying distributed-temperature-sensing (DTS) systems in tight-sand and shale-gas wells for hydraulic-fracturing diagnostics.

The passive nature of fiber-optic sensors allows intervention- and interference-free operation. The inherent long-term reliability of such sensors, combined in a downhole-deployable single optical-fiber cable, makes fiber-optic technology an effective platform for permanent sensing in producing wells. DAS technology has potential for improvements in management of assets across the well’s life cycle, from exploration to operation.

Measuring Wellbore Acoustic Disturbances at the Surface

Surface Interrogator System. The DAS interrogator unit transforms a standard telecom (single-mode) fiber of sever-al kilometers in length into an array of microphones. This works because the interference of back-reflected laser light is affected by acoustic disturbances along the optical fiber. The technology can be deployed in new wells or used in most existing wells in which standard telecom optical fibers have been deployed for DTS purposes.

The DAS system uses a technique called coherent optical time-domain reflectometry, which involves the successive transmission of short pulses of highly coherent light down an optical fiber, and the observation of the very small levels of back-scattered signal caused by nonhomogeneities in the glass core. The system relies on sensing of vibro-acoustic disturbances in the vicinity of the fiber-optic cable.
Technology Focus: Production Operations (March 2012)
Authors: Alhanati Francisco J.S.
Published: February 2015

Technology Focus

At the 2011 SPE Annual Technical Conference and Exhibition in Denver, there were many interesting discussions on shale-gas (and/or liquid-rich) resources. While already an important part of the industry, we are just beginning to identify some of the challenges with these resources and how best to deal with them. With hydraulic fracturing being an integral part of these operations, one area of focus is how to optimize the well geometry and the fracturing treatment to achieve long-term production and high ultimate recovery. Nevertheless, two other key considerations concern where to obtain the huge volumes of water that are required for these fracturing jobs, and what water treatment is required to ensure a safe and problem-free operation. With the need to rely less and less on fresh surface water to minimize the environmental effects, operators have been forced to explore other options, including finding suitable aquifers and/or water-recycling technologies. Some of the papers featured in this issue (or listed as additional reading) illustrate some of these challenges and how companies are trying to address them.

During this last year, we also saw an increase in the use of inflow-control devices in conjunction with horizontal wells in a variety of applications throughout the world. One of the most interesting developments is that of the so-called “autonomous” devices, which should be capable of adjusting themselves on basis of the type of fluid flowing through them (i.e., applying more choking to less-viscous fluids such as water and gas). There also have been interesting advancements in sandface-monitoring systems, as illustrated in two of the papers in the reading list.

Recommended additional reading at OnePetro: www.onepetro.org.

SPE 144032 A Novel Screening Method for Selection of Horizontal-Refracturing Candidates in Shale-Gas Reservoirs by Shekhar Sinha, SPE, Schlumberger, et al. (See JPT, November 2011, page 102.)

SPE 147264 Shale-Gas Water-Treatment Value Chain—A Review of Technologies, Including Case Studies by Patrick Horner, Aqua Pure Ventures, et al.

SPE 145737 The Autonomous RCP Valve—New Technology for Inflow Control in Horizontal Wells by Vidar Mathiesen, Statoil ASA, et al.

SPE 147439 Fiber-Optic Strain Sensing at the Sandface Enables Real-Time Flow Monitoring and Compaction Mitigation in Openhole Applications by Denise M. Earles, SPE, Baker Hughes, et al.

SPE 145581 Ormen Lange: Delivering Production Optimization and an Improved Reservoir Understanding Using a New Cableless Sandface-Monitoring System by B.P. Champion, SPE, Expro, et al.
4D Seismic for Reservoir Management in Carbonates: Does It Work?
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 144228, ’Application of 4D Seismic for Reservoir Management in Carbonates: Does It Work?,’ by Mohamed Saleh Efnik, SPE, and Samsudin Haj Taib, University of Malaya, prepared for the 2011 SPE Enhanced Oil Recovery Conference, Kuala Lumpur, 19-21 July. The paper has not been peer reviewed.

In the past 10 years, time-lapse (4D) seismic has evolved from an academic research topic to a typical method of monitoring reservoir performance. The method is used to provide evidence of saturation changes within the reservoir at field scale. 4D seismic provides data that describe the dynamic behavior of reservoir fluid between wells that otherwise would be limited to small-scale monitoring at borehole scale. Thus, 4D seismic provides sophisticated techniques of reservoir monitoring and management that rely on the integration of geological models, static and dynamic properties of the reservoir rock, and detailed field-production and -pressure data.

Introduction

The feasibility of 4D seismic has evolved with studies that showed that certain rock properties, such as acoustics and pressure, are affected by changes caused by hydrocarbon production over the life of the field. The use of 4D-seismic data in conjunction with reservoir-simulation models and production data enables creation of an internally consistent subsurface model. It has been shown that acoustic impedance (AI) and Poisson’s ratio are related closely to porosity and water-saturation changes in Arne chalks. An increase in porosity causes a decrease in AI; increasing water saturation (at constant porosity) results in a strong increase in Poisson’s ratio.

An extensive seismic program was carried out over a CO2-injection area during a 5-year span to monitor the CO2 storage in a saline aquifer in the North Sea Utsira sand. 4D seismic and other geo-physical techniques were used to obtain information that could help determine reservoir-quality characteristics and predict fluid contacts. Forward modeling of 4D seismic has been shown to be a useful reservoir-management tool. Here, the simulation model was combined with the streamline method for modeling flow, and the ray-Born method for synthetic seismograms was used to compensate for the numerically expensive model because of the large volumes in the subsurface.
Forties Infill Drilling 8 Years Later: Development Driven by 4D Seismic
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 145433, ’Forties Infill Drilling 8 Years On: Continued Success Through the Application of Thorough Development Geoscience Driven by 4D Seismic,’ by Philip Rose, Gregg Barker, Klaas Koster, and Jeff Pyle, Apache North Sea, prepared for the 2011 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 6-8 September. The paper has not been peer reviewed.

In the 8 years since Apache purchased the Forties field, more than 100 in-field targets have been drilled, with an overall success rate of 74%. The campaign resulted in a shortage of sidetrack-donor wells, with a return to surface drilling on all five platforms. To enable full exploitation of the target portfolio, Apache is installing a new 18-slot platform in 2012. Key to success has been a constant drive to push the boundaries of 4D-seismic interpretation and of the lithology prediction from seismic, and the ability to integrate this information with local production and well data.

Introduction

The Forties field, in the UK central North Sea, was purchased by Apache in 2003, at which time it was a giant field in the decline phase of its life. Annualized average production was 41,000 BOPD and declining. No new wells had been drilled in the field since 2001. In the early 1980s, the field produced between 400,000 and 500,000 BOPD. By 2003, the field had produced 2.5 billion bbl of the 4.2- to 5-billion-bbl original oil in place. The field’s remaining recoverable reserves were listed as 144 million BO. Since the purchase, more than 100 drilling targets have been tested, resulting in more than 80 production and four injection completions. As a result of the drilling campaign, annualized average production has remained at approximately 60,000 BOPD since 2005, with total production of more than 150 million BO, of which 75 million BO has been produced from newly drilled wells. As shown in Fig. 1, approximately 70% of the current field production is from wells drilled since the purchase.

Foundation: Data Integration

Use of an integrated multidisciplinary interpretation approach was critical to identify new targets continually. The ability to display well-log-derived attributes with seismic amplitudes, seismic geobodies, and production information in a single interpretation environment was invaluable. The data book contains map locations, illustrations of the pay section with completion history, production history, workover record, and a current completion diagram for every well completed in the field. All interpreters have access to the company’s live production-allocation database. Although many of the infill-drilling targets were driven by seismic interpretation, including the identification of direct hydrocarbon indicators (DHIs) or unswept areas highlighted by time-lapse (4D) seismic, others were generated to replace mechanically failed wells having remaining production potential, and a few targets were generated following the analysis of simulation results.
Innovation: Taking Charge of Completion Innovations
Authors: Imomoh Egbert
Published: February 2015

President's column

The essence of most drilling operations in our industry is to open the maximum length of reservoir formation with the mini-mum damage to the rock surface. This should allow maximum efficient flow of the desired reservoir fluids into the wellbore and to the surface. The proper completion of a well will ensure that production is not denied or restricted, and enough care is taken to ensure that all the investment made in drilling the well is safeguarded. The term “completion” covers a gamut of activities related to stopping the movement of wellbore material into the well, the running of tubing and attachments needed to flow the reservoir fluids to the surface safely, the installation of subsurface equipment to increase production, and to provide well protection. One short article will not be adequate to do justice to this very important element of providing energy for the world.

My first experience with well completions was in the Niger delta where the producing formation is friable sandstone, which is prone to dislodgement when production commences. We used a mixture of sand consolidation chemicals to “glue” the sand matrix through perforations in the production casing. The process required preparation of chemicals at the surface properly tailored to the prevailing temperature and pumped into the selected part of the pay zone. The placement had to be very accurate, as any unconsolidated part of the open reservoir could play havoc with production and surface equipment after the well was brought into production. These wells were relatively simple, as they were vertical and shallow.

Since the first wells were brought into production, a number of completion innovations have been introduced that have permitted the safe and profitable production of oil and gas. Some of them are now routinely used and their process of evolution is now buried in history. Today’s wells are in general much deeper and more complex and therefore have benefitted from innovation to ensure maximum inflow per length of reservoir. Operators carefully choose the form of completion that best suits the formation—including gravel packs, open hole, and multizone, to name a few.
Comments: HSE Now
Authors: Donnelly John
Published: February 2015

Editor's column

This month, SPE will launch a new web- and app-based publication focusing on the health, safety, security, environment, and social responsibility (HSSE-SR) discipline. With news, updates, and technical information needed by oil and gas professionals working in this discipline, HSE Now will be updated continually and will be available on the web and mobile devices such as tablets and smartphones. It will be free to all SPE members.

Unlike other SPE publications, HSE Now will include articles, reports, government documents, and other material from both SPE and non-SPE resources around the globe. The amount of information in this area has exploded in the past decade as the oil and gas industry is being held to higher standards in areas such as environ-mental responsibility, sustainability, and workplace safety. The occurrence of high-profile accidents such as the US Gulf of Mexico Macondo explosion has heightened public scrutiny of industry standards and practices. 

The new periodical also reflects an outreach by SPE to a group within the industry that does not have an obvious professional home. Last year, SPE launched a print publication, Oil and Gas Facilities, targeted to the increasingly important projects, facilities, and construction discipline and the publication has been very well received. The primary objective is to make it easier for SPE members working in this discipline to find critical information they need to do their jobs.  Because the subtopics in this discipline are so diverse, there is no single source of information on the collective topic, and the SPE vehicle will serve as a curator of information, bringing together high-quality SPE and non-SPE information on the discipline.  

An editorial advisory board will help HSE Now plan and develop content. Its members are Roland Moreau, ExxonMobil, chairman and SPE Technical Director for Health, Safety, Security, Environment, and Social Responsibility; Tom Knode, Halliburton; Emmanuel Garland, Total; Herman Vacca, EP Energy; Davide Scotti, Saipem; Dave McLeod, Halliburton; Mark Whittenberg, Schlumberger; Chris Deepak, Halliburton; Clarion Johnson, ExxonMobil; Andrew Wojtanowicz, Louisiana State University.

Moreau describes the increasing importance of HSSE-SR in the industry in this month’s Guest Editorial. Operators, service companies, and others involved in producing oil and gas to meet growing global demand are challenged today to do so safely and in a way that is compatible with the environmental and economic needs of local communities.

SPE is also meeting the demand for more information and dialogue in this area through a growing number of regional HSSE-SR conferences around the world, in addition to workshops and on-demand web events. This month, an SPE Americas HSSR-SR conference will take place in Galveston, Texas, and similar conferences are scheduled this year in London, Lima, and Doha. The SPE International Conference on Health, Safety, and Environment will be held in March 2014 in Long Beach, California.
At-Bit Inclination, Gamma, and Imaging System Tracks Productive Zone in Complex Geology
Authors: Flook Robert , Alexander Will , List Dave , Sencenbaugh Bob , Enoch Breck , Wheeler Aaron J. , Starkey Allen , Rennie Allan
Published: February 2015

Technology Update

In unconventional resource plays and fields with structural or stratigraphic complexities, reliable geosteering of horizontal laterals is essential to economic success. Each foot drilled out of zone represents a potential loss of production revenue. Using real-time logging-while-drilling (LWD) data can reduce directional drilling risk. However, conventional bed boundary imaging tools are typically located far behind the drill bit. This creates a significant lag in response time and increases the odds of exiting the target interval.

The recent introduction of an at-bit inclination, gamma ray, and imaging technology has enabled Fidelity Exploration & Production to optimize well placement in a target formation of the Para-dox Basin in Utah—despite unexpected faults and local changes in formation dip that were not clearly resolved with seismic data.

The Geological Challenge

During the Pennsylvanian period, the Paradox Basin was rapidly subsiding and filling with thick, cyclic sequences of marine carbonates, evaporates, silts, and shales. Relatively thin, reservoir-quality clastic and carbonate formations became interbedded within organic-rich shales, surrounded by thick salt deposits. Salt above and below these self-sourced oil and natural gas reservoirs provides critical sealing capacity, while preserving overpressures generated during hydrocarbon maturation. However, the thick-nesses of potential reservoirs vary as a result of syndepositional faulting and subsequent salt movement, dissolution, and collapse. Many exhibit open, near-vertical fractures controlled by regional tectonics and local folding because of salt flows over anticlines and underlying fault blocks.

Local thickness variations, folding, and subseismic faulting of Paradox reservoirs have presented significant challenges to operators. One target interval, a dolomite-silica silt reservoir enclosed in a fractured and overpressured shale formation, averages 40-ft thickness in southwestern Utah.

Drilling activity there has undergone two distinct phases, with varying degrees of success. The first phase, from the 1960s through the early 1980s, included the drilling and completion of almost a dozen vertical wells. One well was an economic success, producing more than 1 million bbl of oil and establishing the formation’s potential. Horizontal drilling, introduced in the early 1990s, increased the probability of encountering natural fractures that influence production. Roughly half of these wells produced commercial oil, including one that has yielded more than 600,000 bbl to date.
Oil Rim Tool Measures Reservoir Fluids Continuously in Real Time, Below Pump
Authors: Shanks David
Published: February 2015

Technology Update

Defining the reservoir by its porosity, permeability, fluid content, water saturation, and behavior is one of the predrilling goals of exploration and production teams, with the aim of optimizing reservoir production over the life of the field.

Advances in Reservoir Characterization

Very few 2D measurements of any kind are taken from inside a wellbore, except for temperature and reservoir microseismic activity. Distributed temperature sensing (DTS), which uses fiber-optic cables, can provide a full temperature profile. However, to obtain pressure, flow, or fluid information, results are extrapolated and mathematically calculated with an inferred answer. Thus, it does not measure the reservoir directly, continuously, and in real time.

Some oil companies are moving toward time-lapse, 4D, seismic techniques that can identify infill drilling opportunities, predict flood fronts, and help avoid early water breakthroughs, despite the cost and complexity of these techniques. Seismic surveys are mostly for the identification of rock formations and subsurface faults, and much of the fluid analysis is inferred from these rather than directly measured.

Knowledge of the position and thickness of the oil rim in particular is critical for effective reservoir observation. To achieve maximum production, it is important not only to be able to measure the effects of injection operations on a reservoir, but also to monitor long-term reservoir movement and behavior. The only alternative way to keep track of the position of an oil rim is with periodic logging surveys, which can be both inaccurate and expensive.

Advances in seismic survey techniques have enabled much greater analysis of fluid chamber and reservoir movement. The gradual development and deployment of this type of technology has taken more than 50 years from single-point seismic source methods using an electronic transponder to 4D methods, which can map the movements, fluids, and sensitivities in the reservoir.

A Clearer Vision

With dwindling hydrocarbon reserves and increasing oil and gas demand, innovation in characterizing reservoirs is crucial to sustaining supply. Reservoir geophysics incorporating the latest soft-ware and reservoir characterization techniques is bringing significant improvements to production in existing fields.

Production geoscientists are heavily involved in characterizing reservoirs, particularly describing how reservoirs have been affected by ongoing production processes. The combined use of time-lapse and multicomponent data, such as seismic, logging analysis, and DTS, has had a dramatic impact on reservoir understanding that has led to improved production over the life of the field.
Sensing System Provides Synchronized Acoustic Measurements
Authors: JPT staff _
Published: February 2015

Young Technology Showcase

Silixa’s iDAS (intelligent Distributed Acoustic Sensor) offers a solution for permanent and continuous downhole production monitoring and reservoir monitoring by overcoming the cost and technology challenges encountered with traditional point sensors. The iDAS enables wide-aperture acoustic array observation even in harsh environments, like high-pressure, high-temperature wells, and negates the need for irreversible pre-completion sensor placement.

The iDAS measures the full acoustic field along the unmodified optical fiber up to tens of kilometres in length with a spatial resolution down to 1 m, capturing the full amplitude and phase of the incident wave on the sensing optical fiber up to frequencies >100 kHz with a wide dynamic range (>120 dB). The system enables high-quality synchronized coherent digital recording of acoustic waves with no crosstalk at every location along the fiber. These unique attributes make the iDAS technology particularly well-suited to the demanding applications encountered in oil and gas exploration and production.

Principle of Measurement

The iDAS functions by using a method based on optical time-domain reflectometry. When light is emitted into a fiber, the signal is reflected throughout the fiber length. These reflections are the result of a variety of mechanisms, including Rayleigh, Brillouin, and Raman scattering. By monitoring this scatter as a function of time following the emission of each sensing pulse, it is possible to build a map of the time variance of light-scattering properties throughout the fiber. This information can be analyzed to give a measure of the acoustic signal at each sensing zone along the fiber. Silixa’s iDAS uses a new digital optoelectronics architecture to rapidly and accurately measure this backscattered signal with a precision and speed that allows acoustic measurements from very low frequencies (<10 mHz) to high frequencies (>100 kHz). This sensing system can be retrofitted on existing standard optical-fiber cable installations, although superior performance can be achieved by using Silixa’s proprietary cables for logging operations and new permanent installations.

Applications

Silixa’s iDAS technology provides benefits through every stage of the life of a well. Since iDAS makes it possible to map acoustic propagation along the entire length of a borehole, the system creates the opportunity to perform real-time, continuous production and well-integrity monitoring. Further, distributed acoustics can facilitate seismic profiling in harsh, high-temperature downhole environments.

Silixa has also developed a number of installation techniques for permanent as well as logging applications.
Techbits: Wellbore Collision Avoidance and Interceptions - State of the Art
Authors: de Wardt John P. , Mullin Steve , Thorogood John L. , Wright John , Bacon Robert
Published: February 2015

Techbits

This article highlights key knowledge that was shared at the SPE’s “Collision Avoidance and Well Interceptions Applied Technology Workshop” held in Inverness, United Kingdom, in September. It raised awareness of issues concerning wellbore collisions and interceptions.

Planning to ensure that well collisions do not occur during drilling is a complex and demanding task that is often not given the high priority that it requires in drilling programs. Assumptions are made of the validity and accuracy of historical data that is unfounded. Conversely, planning well interceptions when required in operations such as relief wells/drainage intercept wells requires a sound working knowledge of wellbore-positioning technologies and techniques.

Wellbore interceptions and proximity placement are becoming critical applications for the development of some reservoirs, specifically tar sands and coalbed methane. Wellbore collision avoidance is entering the daily skills requirement of drilling engineers as they plan more infill wells and more cluster (pad) drilling. Ultimately, demonstrating the knowledge of the borehole position during the drilling process is becoming a regulatory requirement that demands greater understanding by the drilling engineering community and drilling/asset managers. Are drilling engineers trained, competent, and adhering to procedures designed to manage the intricacies of wellbore surveying requirements as applied to collision avoidance and well interceptions?

The workshop covered the topic under the headings:

Survey-database integrity

Collision-avoidance management

Practical directional drilling

Relief-well design

Interception techniques

The workshop emphasized that wellbore collisions must be treated as high-risk events that must be managed by systematic survey-management procedures. Borehole-position errors are a critical input to subsurface modeling and have a major effect on field economics. Several workshop committee members are also members of the SPE Wellbore Positioning Technical Section (SPE WPTS) that has published two SPE papers on the ellipse of uncertainty error models commonly referred to as the Industry Steering Committee on Wellbore Survey Accuracy (ISCWSA) models.

Summary of the Workshop Workshop attendees shared and learned about current good practices of the complete management cycle of well-positioning activities. Planning, policies, data management, practical application, and technology were all addressed. This was accomplished during presentations, discussions, and breakout sessions with industry experts. Some in-depth presentations and insightful results were produced, including

good practice in designing a survey program

requirements for survey-database management

managing anticollision risk

practical insights into relief-well planning and drilling
Exploring Deep Earth and Deep Space: What Role Does the Petroleum Industry Play?
Authors: Beckwith Robin
Published: February 2015

Hydrocarbons

Exciting hydrocarbon discoveries of mind-bending quantities are being made in the far reaches of our solar system and our own Milky Way galaxy. A new paper (http://www.jpl.nasa.gov/news/news.php?release=2013-010) by scientists on NASA’s Cassini-Huygens mission finds that blocks of hydrocarbon ice might float upon the surface of existing lakes and seas of liquid methane and ethane on Saturn’s largest moon, Titan. Findings from a recent study (http://arxiv.org/pdf/1210.8178v1) of the Horsehead Nebula, part of the Orion Constellation, propose the discovery of a new interstellar molecule, the cation C3H+ (propynylidyne). C3H+ was one of 30 molecules identified in the region, including several small hydrocarbons.

Titan is about a billion miles away from Earth (1.5 light-hours) and the Horsehead Nebula is 1,300 light-years away (7.6 quadrillion miles). Why should the petroleum industry pay attention to the existence of hydrocarbons at impracticable distances from Earth?

Perhaps instead it would make more sense to focus on deep Earth.

However, there is a sense in which attempting to look below the surface of our own planet is a far more difficult task than exploring outer space: We can send a human 238,900 miles away to the surface of our moon, and humans routinely spend months on-board the International Space Station, which is maintained at an orbital altitude of between 205 and 255 miles above Earth.

But only three humans have been to the Challenger Deep, first sounded during the HMS Challenger expedition (December 1872 to May 1876) at the southern end of the 1,580-mile-long, crescent-shaped Mariana Trench some 210 miles southwest of Guam, which at 36,069±131 ft (a little less than 7 miles) below sea level is the deepest point in Earth’s oceans. Jacques Piccard and Don Walsh spent only 20 minutes at a depth of 35,814 ft on 20 January 1960, in the bathyscaphe Trieste. Filmmaker James Cameron spent a little over 3 hours there on 25 March 2012, in his specialized sub-marine called the Deepsea Challenger.

A few deep-sea remotely operated vehicles have also plumbed the depths of the Challenger Deep.

Of course, for humans to actually enter the Earth’s crust is impossible without clearing and bolstering a mine-shaft. The deepest humans have ever traveled into the Earth is at the Tau-Tona gold mine, near Carletonville, South Africa, which extends some 2.4 miles underground.
Q&A with Ali Vezvaei, Siemens Middle East
Authors: Vezvaei Ali
Published: February 2015

Q&A

What was Siemens’ involvement in the Habshan-Fujairah oil pipeline project?

Siemens was involved in this strategically important project from the very beginning, working in harmony with a series of other contractors on a tight timescale to deliver an alternative option to shipping crude oil through the Strait of Hormuz.

Siemens’ contribution to the project was to supply the entire control and automation system of the pipeline—its “brain,” if you like. For this, we had to develop a relatively complex system, enlisting the assistance of a team from Europe to work with our local experts in order to design, finalize, and implement a suitably comprehensive solution.

Essentially, the Siemens control and automation system at the Habshan-Fujairah facility is designed to ensure that the pipeline, under normal operation, can be accurately managed from a central location, including measuring and controlling the flow of oil, shifting the lines, monitoring and controlling different stations and streams, and supervising other variables fundamental to the reliable day-to-day operation of the pipeline.

Within the system there is also a series of different modules and platforms that allow for operation under alternative conditions, for instance, in the case of an emergency. Any solution for the automation and control of critical infrastructure like this needs to be robust, and in a four-station pipeline that’s almost 400-km long, you cannot compromise on safety and reliability, especially when there’s a workforce involved.

What are the main benefits of an automated control system like this?

Firstly, it enables the pipeline to run safely and reliably. Safety is paramount, and our automation and control system is designed to protect the pipeline and its operation in a comprehensive range of scenarios. It also reduces the requirement to have a workforce stationed in the field—with obvious safety implications—in addition to lowering the potential for unreliable and sometimes time-intensive communications.

Secondly, a system like this introduces enhanced efficiency. With accurate, real-time monitoring comes the ability to swiftly react to requirement changes for various aspects of the pipeline, allowing operators to maintain the facility at optimum efficiency under any conditions.

The pipeline is intended to be customer operated. What level of training is involved?

The automation system for the Habshan-Fujairah oil pipeline has been designed to allow the end-user to take over the operation and control of the pipeline. It’s important that the team is familiar with both the day-to-day running of the system and also its operation in a wide range of other scenarios. Naturally this requires extensive training of the customer’s workforce.
Survey Identifies Industry Skill Gaps
Authors: JPT staff _
Published: February 2015

Talent & Technology

Employees place great emphasis on training and development opportunities when choosing employers, and lack of training and skills development could hamper the oil and gas industry’s short-term potential for production growth. Those were two of the key findings in a survey of industry professionals designed to build a current picture of the level of skills in the global engineering community and determine the importance that the oil and gas industry places on learning and skills development. The survey was conducted by SPE and sponsored by BP. Of the respondents, 47% were engineers and 25% were managers.

The survey confirmed that a wide range of skills are important for a successful career in the oil and gas industry, and that employees place great emphasis on training and development opportunities when choosing employers. The ability to learn, teamwork, communication skills, work ethic, and technical skills are some of the most important skills required for a career in the industry. Universities play an important role in equipping graduates for the start of their career and are seen to be particularly good at providing computer skills, knowledge, technical skills, and analytical skills. Upon starting a career, the majority (86.8%) of employees require training, even if only a little. Most survey respondents (82.4%) said they expect their employer to provide them with some of this training, which tends to be a combination of formal and informal. Only about a tenth (11.1%) expect the employer to provide all of their training.

Two-thirds (65.7%) of respondents said they have received formal training, which consists of technical training (76.5%), soft skills training (57.8%), and management and finance training (44.3%). Outside companies deliver the greatest share of this formal training. Formal technical training is mostly delivered by a mix of outside companies, workshops, on-the-job training, and internal training programs. Soft skills training often is provided by out-side companies (28%) or internal training programs (24%). Of the formal training received, technical training was rated the most important in helping to meet the daily responsibilities of their job role. A majority of respondents (76.8%) said they are satisfied with the formal training they received, particularly the quality and content. However, improvements could be made to increase training budgets and the amount of training and time made available, as a tenth of survey respondents said they are dissatisfied with these aspects of training programs and opportunities.
Identification and Prediction of Wells Susceptible to Sulfide Stress Cracking
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 160489, ’Identification of SSC (Sulfide-Stress-Cracking) -Susceptible Wells and Risk Prediction,’ by Tapan Chakrabarty and Richard J. Smith, Imperial Oil Resources, prepared for the 2012 SPE Heavy Oil Conference Canada, Calgary, 12-14 June. The paper has not been peer reviewed.

Hydrogen sulfide (H2S) generated by aquathermolysis—a high-temperature reaction of condensed steam (water) with sulfur-bearing bitumen in the reservoir rock—may increase the risk of sulfide stress cracking (SSC) in cyclic-steam-stimulation (CSS) wells. Identifying the SSC-susceptible wells is important in terms of reducing SSC risk by allocating resources to and implementing proactive intervention measures at the SSC-susceptible wells. A comprehensive research program, with a dedicated instrumented CSS well as the centerpiece, has been undertaken with the objectives of characterizing H2S evolution in the wellbore and developing a tool for identifying the SSC-susceptible wells.

Introduction

Imperial Oil is using CSS commercially to recover bitumen from the Clearwater formation at the Cold Lake field in Alberta, Canada. In this process, the reservoir is stimulated by injecting high-pressure/high-temperature steam to reduce the bitumen viscosity and produce the thinned bitumen through the same well in a cyclical manner. In a given well, steam injection is through the casing, liquid (bitumen and condensed steam) production is through the tubing, and gas production is mainly through the casing annulus. It is the casing that is susceptible to SSC, as shown in a small casing section retrieved from a Cold Lake CSS well (Fig. 1). SSC in a CSS well is induced by H2S that is generated by the reaction, termed aquathermolysis, between condensed steam and sulfur-bearing bitumen.

SSC increases with an increase in H2S partial pressure (pH2S) and with a decrease in well temperature. The inverse temperature effect is attributed to the diffusion of hydrogen atoms—a product of the reaction between H2S and iron—through the casing metal matrix. At a lower temperature, the hydro-gen diffusion is slower and the hydrogen accumulation inside the casing wall is higher, leading to a higher stress build-up and an increased SSC susceptibility.

To reduce the risk of SSC in CSS wells at Cold Lake, Imperial Oil has implemented an extensive casing-integrity-assurance program that includes

Measuring the H2S during production in all the wells as they cool down to lower than 70°C

Shutting in an SSC-susceptible well

Purging the casing annulus of a shut-in well with nitrogen to lower the H2S level in the wellbore
Enhanced RSS Technology Pushes Drilling Envelope
Authors: Figueredo Cesar
Published: February 2015

Technology Update

Increasing technical demands are pushing the envelope of rotary steerable system (RSS) drilling technology. The growing challenges of directional drilling in hard formations, borehole stability issues, difficult hole trajectories, and harsh downhole environments all are placing increasing demands on drilling and adding costs and risks to operations.

RSS advancements have played a key role in pushing drilling into new frontiers such as deepwater and unconventional basins. As wells have become more complex and difficult, the industry seeks continuing advancements to enable the economic development of previously inaccessible resources in a variety of environments.

The Schlumberger PowerDrive Orbit enhanced RSS (Fig. 1) expands the ability to complete multiple functions in one run, tolerating higher revolutions per minute while maintaining good trajectory control, minimizing tortuosity, and accommodating challenging hydraulic designs and muds formulated for more aggressive drilling.

Addressing Challenges

The technology was engineered to address the most challenging drilling conditions and provide the reliability and efficiency needed to plan one run per section from shoe to total depth. The tool reduces the number of trips in and out of the hole, decreases the risk of differential and mechanical sticking, and improves hole cleaning and conditioning capabilities.

The enhanced RSS system includes a newly designed pad actuator, thus increasing reliability and enhancing trajectory control by use of self-steering automation on any type of rig worldwide. The system also offers an optional, or on-demand, stronger pad design to provide greater durability in highly abrasive formations.

In wells that typically would require two or three runs to drill one section, the new design enables operators to drill a section in a single run with improved performance. It also expands the revolution rate limits, tolerating up to 350 RPM, from the current limit of 220 RPM, while maintaining directional control and consistent steerability.

Enhancing Existing Technology

The new RSS system was designed to boost the effectiveness of existing technology. With an improved pad force, push-the-bit system for consistent dogleg severity at higher revolutions per minute, the new technology pushes the operating envelope of PowerDrive pushthe- bit systems. When combined with the PowerDrive vorteX powered RSS, it offers a wider tolerance for higher revolutions per minute and torque downhole.
Technology Focus: Hydraulic Fracturing (March 2014)
Authors: Olson Karen
Published: February 2015

Technology Focus

At the 2014 SPE Hydraulic Fracturing Technology Conference in February, former Texas A&M Department of Petroleum Engineering head Stephen A. Holditch received a well-deserved lifetime achievement recognition, the Legends of Hydraulic Fracturing Award. Among the reasons he received this award was that he has demonstrated throughout his career a passion for understanding and explaining to his peers and colleagues what happens during hydraulic fracturing. Through his consulting company and as a professor and department head, he passed his passion along to others. He served on many masters and doctoral candidate committees and directed numerous graduate-student research projects. He continued to spread knowledge by authoring more than 100 SPE papers.

With the rising importance of hydraulic fracturing in the development of unconventional plays and deepwater projects, who among you will be a future legend of hydraulic fracturing? Who among you possesses the passion, the drive to really understand fracturing in these horizons and to advance the science and understanding for yourself, your company, the industry, and the world? Who will take the time to document their work?

As I survey the industry, its leadership styles and career paths, I see familiar themes. Recent graduates come into completions, do their mandatory stint, and then move to the next rotation in order to qualify ultimately for a promotion into management. I am not disparaging this, and I believe in the importance of a well-rounded career as well as an understanding of the well/project life cycle.

But, in closing, I will state that I also believe an engineer should develop an expertise in at least one aspect of their work. So, ask yourself two questions: What is my expertise? What do I want to be remembered for? And then, look inward and contemplate, “What will be my legacy?” JPT

Recommended additional reading at OnePetro: www.onepetro.org.

SPE 166332 Characterizing Hydraulic Fracturing With a Tendency-for-Shear- Stimulation Test by Mark McClure, The University of Texas at Austin, et al.

SPE 163824 Development and Use of High-TDS Recycled Produced Water for Crosslinked-Gel-Based Hydraulic Fracturing by R. LeBas, Halliburton, et al.

SPE 166298 Influence of Hydraulic Fractures on Wellbore/Sandface Temperatures During Production by J.F. App, Chevron Energy Technology Company

SPE 166550 Offshore Horizontal-Well Fracturing: Operational Optimization in the Southern North Sea by Marc Langford, Centrica, et al.
Slurrified Heavy-Oil-Reservoir Extraction as a Recovery Method
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 165498, ’Slurrified Heavy-Oil-Reservoir Extraction (SHORE): A Nonthermal, In-Situ Recovery Method,’ by David P. Yale and Jianlin Wang, ExxonMobil Upstream Research; Steven W. Meier, Eric Herbolzheimer, and Arnold P. Kushnick, ExxonMobil Research and Engineering; Neal L. Adair and Sergio A. Leonardi, ExxonMobil Upstream Research; and Richard J. Smith, Imperial Oil Resources, prepared for the 2013 SPE Heavy Oil Conference—Canada, Calgary, 11-13 June. The paper has not been peer reviewed.

This paper presents a concept for recovery in Canadian oil sands that uses water injection to condition a reservoir interval sufficiently to relieve the overburden stress on the oil sand and increase its porosity and permeability. The ability of the process to work in thinner and more geologically complex reservoirs compared with other in-situ processes, and with lower CO2 and surface footprints than those seen in thermal and mining processes, could make this an attractive alternative recovery process for shallow- to intermediate-depth in-situ bitumen resources.

Introduction

Canadian oil-sands recovery is challenged by the high and ultrahigh viscosity of the heavy oil and bitumen trapped within the generally unconsolidated sand matrix of these reservoirs. Steam processes have dominated the in situ recovery of this resource, but steam/ solvent and solvent-only processes are currently being field tested. Steam processes, especially low-pressure processes such as steam-assisted gravity drainage (SAGD), are challenged by both a high degree of geologic heterogeneity and thin pay zones.

In-Situ Mining of Oil Sands

The very shallow (less than 70-m) depth of a large portion of the oil-sand deposits of Canada has made their surface mining a technically feasible and economical method of recovering the bitumen from the shallowest portion of the oil sands. The success of surface mining for bitumen has led others to propose and test in-situ bitumen mining processes. Hydraulic mining of the oil sands from a borehole has a rich patent literature but few conclusive field tests. The basic concept is that a high-pressure, downhole water jet could disrupt the unconsolidated sand matrix around the wellbore such that a bitumen/water/sand slurry could then be produced to the surface for bitumen extraction with surface-mining techniques. The process is technically challenged by the limited volume of hydrocarbons that can be recovered from any given wellbore and the limited “cavern” size that can be supported without roof collapse in these unconsolidated sand/shale geologic environments.