bluuebunny/crossref_metadata_2025 huggingface dataset:
Multiple Factors Drive Decisions Toward Wet or Dry Trees in Deepwater Projects
Authors: Wilson Adam
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 24517, ’Deepwater Development: Wet or Dry Tree?’ by D. Reid, M. Dekker, SPE, and D. Nunez, Shell, prepared for the 2013 Offshore Technology Conference Brasil, Rio de Janeiro, Brazil, 29-31 October. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.

This paper explores the interplay between field development and lifecycle reservoir management and the selection and operation of dry- or wet-tree host systems for the development and production of deepwater oil and gas fields. Drawing on insights from recent deepwater projects, the selection criteria related to development and reservoir management are highlighted to show the advantages and limitation of the two different host concepts.

Introduction

In deep water, it is common for approximately one-third of the initial capital investment to be related to the host system. Selection of the host concept is critical and is dependent on a robust understanding of the many upfront development drivers.

The host is ultimately the linchpin in the overall development system and is critical to delivering a solution that maximizes economic value during the life of the project, to providing a degree of mitigation against key reservoir and production uncertainties that are inherent in deepwater developments, and to providing flexibility to capture any potential future production upsides that have been identified in the proximal development location.

One of the more important decisions related to deepwater host selection is whether to adopt a dry- or wet-tree system. Both systems offer distinct advantages and disadvantages, depending on the context of their application. The selection of a dry- or wet-tree system should be made in the context of the overall development system evaluation.

Wet- and Dry-Tree Deepwater Host Systems

At a high level, deepwater host development has evolved into four major options, each with various degrees of flexibility in shape and design:

Tension-leg platforms (TLPs)

Moored semisubmersible platforms

Spar platform concepts (conventional, truss, and single-column floater)

Floating production, storage, and offload (FPSO) vessels
Heavy-Oil Papa-Terra Project Uses Innovative Solutions in Deep Water
Authors: Wilson Adam
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 24504, ’Papa-Terra Project: Use of Innovative Solutions for Heavy Oil in Deep Water,’ by D.S. Condessa, G.S. Damno, S.C. Vieira, and W.P. Goncalves, Petrobras, prepared for the 2013 Offshore Technology Conference Brasil, Rio de Janeiro, Brazil, 29-31 October. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.

The Papa-Terra field in the Campos basin in Brazil is identified as having an oil interval of 14.6°API in turbidite sandstones. Because of the high-viscosity oil and low-API grade, innovative solutions and technological advances were incorporated into the project. The development uses an integrated production system consisting of a floating production, storage, and offloading (FPSO) vehicle connected to a tension-leg wellhead platform (TLWP) and dry completion wells. This allows the production of ultraheavy oil in deep water and enables rapid intervention for maintenance of electric submersible pumps (ESP).

Introduction

Because of the properties of the oil from the Papa-Terra field (high viscosity at low temperatures and low gas/oil ratio), the whole production development concept of the field was driven by artificial lift and flow-assurance requirements.

This led Petrobras to a field-development concept that uses two production units, an FPSO (P-63) and a TLWP (P-61), 350 m apart.

The P-61 platform will be connected with 13 dry-completion wells, and all production will be exported to P-63, where it will be joined with the production from five wet-completion wells to be processed. The TLWP will not have a process plant to separate oil, gas, and water and will transfer all produced fluids to FPSO P-63 through multiphase pumps.

As a secondary recovery method, 10 injector wells will be placed at the reservoir extremities to maintain pressure in the reservoir (Fig. 1).

As a consequence of this development, and mainly because of the oil properties, the items that needed to be developed to make the project technically viable and economical attractive are

High-power ESP

TLWP as a production unit

Conductor-driven installation

Thermal-insulated TLWP risers

Tender-assisted drilling (TAD) unit

Fluid-transfer lines at midwater

Electrical-heated flexible pipe
Technology Focus: Intelligent Fields Technology (May 2014)
Authors: Hudson John
Published: February 2015

Technology Focus

What is taking so long? Well, more than a decade into the intelligent-fields initiative, this is a question that remains prominent. That a clear business case supports investments in the area was settled years ago for most; but, within the variety of tactics an operator takes and even greater diversity in the particular products and services providers develop within this space, we have seen a mixture of results. Furthermore, leveraging success from a demonstration project into sustained value delivery and across multiple assets or divisions can be elusive. So, it is understandable and healthy when managers challenge a sustained expense that fails to provide the value that was promised. What then are the markers of an initiative that should be started or sustained?

Are you solving the right problem? Choose a problem that allows your company to learn while delivering incremental value over multiple applications. In my company, we were able to deliver a great return by deploying a relatively simple analytics solution globally to most of our oil production over 5+ years, delivering incremental value while working through the organizational changes.

Is it a good fit for your people? Is your organization able to learn and change to make it work, and do you have the right people who can stay with it until the business owns the change? When key people move after an early declaration of success, fragile changes often falter.

Can you commit to making it work? You can drive value from, and even turn around, a struggling initiative (even one employing a suboptimal solution) when you give the right people the space to learn and deliver against the right problem. There will be bumps, so count the costs up front and ensure that the organization is ready for the challenges. JPT

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

SPE 167821 A Smart Flow for Smart Wells: Reactive and Proactive Modes by G.A. Carvajal, Halliburton, et al.

SPE 164348 Smart Well With Autonomous Inflow-Control-Valve Technology by Haavard Aakre, InflowControl/Telemark University, et al.

SPE 166507 Prototype Test of an All- Electric Intelligent-Completion System for Extreme-Reservoir-Contact Wells by Brett Bouldin, Saudi Aramco, et al.
Innovative Geosteering Technology in Multilateral Wells
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24002, ’Innovative Geosteering Technology Used in Drilling Smart Multilateral Wells, Kuwait,’ by T. El Gezeery, A. Aziz Ismael, K. Al-Anezi, G.S. Padhy, Fawaz Al Saqran, A. Abdul-Latif, and J. Silambuchelvan, Kuwait Oil Company, and J. Estarabadi and G. Ferroni, Geolog International, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.

The Burgan reservoir in Kuwait has the potential for premature water breakthrough, leaving behind bypassed zones of oil. The placement and completion of horizontal wells in such reservoirs is a challenge necessitating a collaborative approach from petroleum geoscience, reservoir engineering, and petroleum engineering. This paper describes placement of horizontal wells in this kind of heterogeneous reservoir through an integrated approach.

Introduction

The Minagish field was discovered in 1959 and is located in the southwestern part of Kuwait. It contains several reservoir intervals in its stratigraphic column, varying from Early Jurassic to Late Cretaceous. The field is situated 12 km northwest from the West Umm Gudair field (Fig. 1). The field has been penetrated by more than 180 wells. The field structure of the Burgan formation is a closed elongated asymmetrical anticline oriented in a north/south direction. The top of the Burgan structure is located at approximately 5,500-ft true vertical depth (TVD) minus the elevation above mean sea level of the depth reference point of the well.

Regional Geology. The Burgan formation consists of a lower braided river system with stacked sand bodies. The sediment ranges from fine to medium grain sizes, and the porosities are high enough for lateral migration. On top of the upper Burgan channels, the sediments are generally finer but still retain a fluvial character. The amount of shale is higher. The marsh and tidal sediments, which consist of fine sands, silty sands, and sandy silts, seem to be of lower connectivity for vertical migration. The porosity is relatively low (between 15 and 18%), and the minimum of the measured permeability is close to 1 md for these layers. It seems that these shaly sediments can act as permeability barriers for vertical migration, but oil is observed in all channels and has been able to reach the reservoirs. This complex channel geometry makes these reservoirs the most challenging clastic reservoirs in the Minagish field.
Conversations: The Pond in Which We Live
Authors: Fattahi Behrooz
Published: February 2015

President's column

The balance between the global supply and demand for crude oil is becoming progressively tighter. Recent projections show that the gap between the oil supply and demand will grow dramatically, to perhaps as much as 20 million B/D by 2030, even with painful conservation measures in place. To keep up with the increasing demand, the petroleum industry is facing a variety of challenges, including development of an adequate supply of a skilled workforce, collaboration on the development and rapid deployment of leading-edge technologies needed to access unconventional resources, and communication to the public at large about our role as an industry and the noble causes that we pursue.

As we face these global and complex challenges, we must increasingly incorporate the concept of sustainability in our operational framework. At first glance, the term sustainability may seem intimidating to some. However, our industry has been focusing on the concept or its components for a long time, but under different descriptive terms—optimizing production, maximizing reserves, reducing cost, cutting waste, increasing efficiency, optimizing processes, minimizing footprint, maximizing safety, reducing environmental impact, and increasing corporate social responsibility. We have spent considerable efforts—heavy investments of time and capital or human resources—in achieving these goals. Thus, for our industry, the gap between what we have been doing and what we need to do is much narrower than what it is perceived to be.

The notion of “sustainability” was more clearly defined through the work of the United Nations’ Brundtland Commission, whose report on sustainable development “Our Common Future” was published in 1987.1 Sustainability was summarized as “Meeting the needs of the present without compromising the ability of future generations to meet their own needs.”

Sustainability is an essential ingredient of our industry’s activities, a diverse concept of many elements that are embedded into the fabric of our daily operation. We practice it, and we create value by integrating sustainability into our strategies and business models. In pursuing better performance, we master sustainability. Yet, we may not have been too mindful of its true meaning in the past. It is only in recent years that the concept of sustainability has moved from the background into the limelight. Sustainability has become the cornerstone of our operation from the upstream to downstream.

Many companies have developed measures and key performance indicators to satisfy their corporate social responsibility, and to ensure that they remain sustainable in many aspects of their operation. While these are important, taken individually, such undertakings are too fragmented; a more collective approach will need to become the subject of discussion in more global conferences and technical meetings, and topics for best-practices workshops. SPE can play a significant role by facilitating such opportunities.
Techbits: Mumbai Workshop Explores Deepwater Strategies
Authors: JPT staff _
Published: February 2015

Techbits

Recognizing the growing potential of deepwater developments off the coast of India, SPE hosted its second deepwater-focused applied technology workshop (ATW) in Mumbai in less than 2 years.  The ATW, “Unlocking Deepwater Potential: Strategies and Technologies,” brought together 131 delegates from 11 countries and 40 companies to share information and help Indian companies assimilate the knowledge they will need to monetize India’s deepwater assets.

Sudhir Vasudeva, director (Offshore)-ONGC and ATW Steering Committee chair, opened the ATW with an address describing India’s deepwater potential. The country’s deepwater regions hold approximately 51 billion bbl of oil and gas equivalent in a sedimentary area spanning 1.35 million km2. Thus far 31 hydrocarbon discoveries have been made—26 gas discoveries and the remaining 5 oil and gas discoveries. The discoveries are spread over Mahanadi, Krishna-Godavari, and Cauvery basins off the east coast of India, which is poised to be a gas hub of Asia.

Vasudeva projected that given India’s gross-domestic-product growth rate of 8–9%, hydrocarbon requirements will increase from the current level of 125 million tonnes of oil equivalent (toe) to 435 million toe in the next 25 years. Global energy consumption is expected to grow by 50% over the same period, putting the onus on the oil and gas industry to find more reserves and curb production declines in existing assets. After 2012, deep water is the only sector which is expected to grow continuously to meet burgeoning global demand.

R.S. Sharma of ONGC next stressed that because 43% of India’s sedimentary basins lie in deep and ultradeep water, the E&P industry has ample exploration opportunities here. However, he acknowledged that the pace of technological progress is sometimes too rapid for operators, who need to have a great deal of confidence and assurance in technologies prior to bidding for deepwater blocks. He stated that critical areas for study going forward include drilling and completions; subsea facilities; and health, safety, and environmental factors.

Pushing Boundaries

The first technical session provided case histories highlighting two recent deepwater developments from different parts of the world. K.V.K. Prasad of Shell Technology India first presented the development strategy for Shell’s Perdido oil field in the US Gulf of Mexico (GOM). Operational and subsurface challenges included extreme water depth (8,000 ft at the platform), extreme metocean conditions, rugged sea floor, flow assurance, a high-risk reservoir (the first Paleogene production in the GOM), low pressure, and high gas-to-oil ratio.
Deepwater-Development Production and Export Options
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 123415, ’Deepwater-Development Production and Export Options,’ by W.D. Hartell, SPE, and J.R. Greenwald, Hess Corporation, prepared for the 2009 SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, 4-6 August.

Deepwater discovery and development activities can be far from existing infra-structure, such as other facilities and pipelines. The choice of production and export options for hydrocarbon liquid and gas is important and is affected by distance to other infrastructure and by water depth, geohazards, reservoir-fluid characteristics, production rates, and reserves. In Southeast Asia, deepwater developments often are hundreds of kilometers from onshore markets, so the development production and export options must be wide to obtain economic and timely choices.   

Introduction

As deepwater developments move into more-remote locations in Southeast Asia, options to develop these “stranded” resources are becoming more challenging. Industry advancements for developing these resources provide multiple options for production and export. Prospective deepwater locations in eastern Indonesia, Papua New Guinea, Philippines, South China Sea, and Australia are gas prone and are long distances from market. Technical and commercial foundations for floating gas production and nonpipeline-export options in Southeast Asia are examined.

Production and Export Options

Given the assumptions of a remote, deepwater hydrocarbon development with hydrocarbon liquids and gas, it is likely that a development scenario would be as follows. Subsea wells would be spread over the field, either as distributed single wells or grouped into drill-center clusters. Production would move from the seabed manifolds in some number of production risers, steel catenary risers, buoyant riser towers, flexible risers, or some combination of these. On the surface of the ocean, there would be a floating production host [i.e., spar, tension-leg platform (TLP), semisubmersible, or a floating production, storage, and offloading (FPSO) vessel].

Conventional gas-export options for remote deepwater locations, such as long-distance gas pipelines requiring compression facilities along the route to markets, are likely to be very expensive. They may be technically too challenging if combined with sea-bed geohazard challenges such as deep trenches, unstable slopes, or areas of seismic activity. These challenges and high costs lead to consideration of floating production options such as processing the gas into more-transportable products.

Gas-Market Options. Compressed Natural Gas (CNG). CNG can be an attractive option (or partial solution) where distance to markets is not too great. It is an attractive option with lower investment needs (i.e., cheaper production facilities, transport vessels, and discharge facilities).
Worldwide Deepwater Petroleum Exploration and Development Prospectivity: Comparative Analysis of Efforts and Outcomes
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 125085, ’Worldwide Deepwater Petroleum Exploration and Development Prospectivity: Comparative Analysis of Efforts and Outcomes,’ by Omowumi O. Iledare, SPE, Louisiana State University, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October.

Empirical indicators derived from deepwater-specific data show that the expansion in deepwater operations is a response to global oil demand as onshore petroleum resources deplete. A study showed that the evolution of deepwater development is very pronounced around the three Atlantic basin deepwater zones (Africa, Latin America, and North American Gulf of Mexico). 

Introduction

The empirical indicators were derived from deepwater-specific data obtained from private and public sources, including an online private database purchased from Infield Oil Field Systems, information collected over time at the Center for Energy Studies, and public data from the US Department of the Interior online database of the Minerals Management Service. Here, deepwater operations are defined as Slope, water-depth range between 200 and 400 m; Deep, water-depth range of 400 to 1500 m; and Ultradeep, water depth greater than 1500 m. Operating firms are classified as an international oil company (IOC), a national oil company (NOC), or a local/independent oil company (LOC). Worldwide, deepwater petroleum basins were classified into five regions—Africa, Latin America, North America, Europe, and other (Asia, Australasia, Middle East, and the Caspian). The study period was 1983–2007.

Factors Affecting Deepwater Operations

Petroleum pricing encourages companies to search for and develop petroleum resources, including the more difficult areas such as the deep offshore. Technology progress in geological-information gathering and processing has made exploration and production operations more efficient. Advances in exploration, drilling, completion, and production technologies have made the search for and development of petroleum more cost effective and environmentally responsible. Frontier areas considered uneconomical and too difficult a few decades ago have become prime targets for petroleum exploration and development as a result of improved imaging technologies, including 3D-seismic and time-lapse systems.

Open access to petroleum resources in deep water is wider in the three Atlantic basin deepwater zones—Africa, Latin America, and the Gulf of Mexico. Currently, most deepwater operations and activity are concentrated in Africa, Latin America, and the US Gulf of Mexico.

Global Appraisal

Attributes of worldwide deepwater prospectivity include fields discovered, fields on stream, discovery-to-production lag, field-depletion life, operational wells, wells under development, and future wells. Well completions have either subsea or surface wellheads.
Technology Focus: EOR Operations (June 2010)
Authors: Bonet-Cunha Luciane
Published: February 2015

Technology Focus

The world has not changed much the past 4 to 5 years. However, we do know a couple of things that have changed. One that affects the energy industry and our daily lives is the price of oil, which has gone up and stayed up. This fact, together with the decrease in the number of new discoveries and the ever-increasing number of maturing fields worldwide, has augmented attention in the enhanced-oil-recovery (EOR) area. There is a huge target out there in the form of residual hydrocarbons. The oil industry’s common goal is to move these resources to reserves and do it safely in an environmentally responsible, reliable, and cost-effective way. EOR technologies are vital in achieving this goal. As a result, many recently planned EOR projects are being implemented and others will be implemented in the coming years.

However, despite many developments and successful implementations, EOR is still a risky business, low on the learning curve and in reliability. Important success factors for an EOR project are a robust characterization of the reservoir, use of reliable reservoir-surveillance technologies, and implementation of efficient operations with minimized operational costs.

To be successful when applying an EOR process, it is critical to address the proxy of ongoing operations and to achieve more-efficient operations workflows. These workflows require a triangular collaboration between oil companies, suppliers, and R&D institutes working together to find creative solutions to produce the oil and gas and to develop new technologies. The papers selected for this feature illustrate a few examples of the latest accomplishments of suppliers of new technologies, along with customers who are applying them. I hope you will find them of interest.

EOR Operations additional reading available at OnePetro: www.onepetro.org

SPE 124614 • “Determining Reservoir Properties and Flood Performance From Tracer-Test Analysis” by G. Michael Shook, SPE, Chevron, et al.

SPE 122018 • “Overcoming Poroelastic Behavior in the Water-Injector Wells in the Kikeh Deepwater Development” by Tamara Webb, SPE, Murphy Oil, et al.

IPTC 13346 • “Staged Design of an EOR Pilot” by B.L. Adibhatla, SPE, ExxonMobil, et al.
Case History: Steam-Injection Monitoring With Optical-Fiber Distributed-Temperature Sensing
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 127937, ’Case History - Steam-Injection Monitoring with Optical-Fiber Distributed Temperature Sensing,’ by Marcelo A.P. Batocchio, SPE, Halliburton, and Adriana L.C. Triques, Hardy L.C. Pereira Pinto, Luis A.S. de Lima, Carlos F.S. Souza, and Ronaldo G. Izetti, Petrobras, prepared for the 2010 SPE Intelligent Energy Conference and Exhibition, Utrecht, The Netherlands, 23-25 March.

A project was initiated by Petrobras to map the steam-front progress in a steam-assisted-production heavy-oil field. A distributed-temperature-sensing (DTS) system was installed to monitor the temperature distribution in a wellbore of a pilot program having three producers and one continuous-steam-injection well.  

Introduction

In heavy-oil fields produced by steam injection, companies seek information to improve the drive mechanism that moves the crude oil into the wellbore. Monitoring equipment and interpretive-software tools help to achieve production requirements, maintain economic feasibility, and promote safety. In this project, high-temperature conditions were factors also.

Optical-fiber DTS is a downhole-monitoring technology that provides permanent and continuous well-temperature profiling. This method enables real-time data collection, whereas traditional downhole monitoring during production provides temperature data only at a fixed point for each reading. Alternatively, wireline temperature logs can be run, but this method does not offer continuous monitoring and it affects production. With the DTS technique, the optical fiber typically is attached to the tubing and provides a complete log of the well temperature for each reading, enabling permanent and continuous monitoring without production interruption. Steam-front progress, which can improve the understanding of the reservoir geological model, can be followed; steam-breakthrough can be identified; and improved injection-efficiency then can be achieved.

Project Implementation

Estreito is an onshore field in northeast Brazil, 180 km from the city of Natal. This field is part of the Potiguar basin. The main reservoirs are Açu 100 and Açu 50/60, which are part of the Açu formation. These shallow reservoirs (approximately 200 m deep) originated from a fluvial depositional system. They have strong heterogeneities, have a strong active bottom aquifer (Açu 100), and are controlled by an ensemble of faults known as Carnaubais. The 15°API oil has high viscosity (2,000 cp).

Cyclic steam injection began in 1984 as an improved-recovery process. This method is no longer economically viable and is being replaced by continuous steam injection.

The efficiency of continuous steam injection is related directly to knowledge of heat-flow paths, which is reflected in the steam/oil ratio and the recovery factor of the area. Therefore, the operator has monitored heat transfer throughout the field since the beginning of steam injection.
Combining Distributed-Temperature Sensing With Inflow-Control Devices for Improved Injection Profile
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 127772, ’Combining Distributed-Temperature Sensing With Inflow-Control Devices Provides Improved Injection Profile With Real-Time Measurement in Power-Water Injector Wells,’ by Drew Hembling, and Garo Berberian, SPE, Saudi Aramco, and Mark Watson, Sam Simonian, and Garth Naldrett, SPE, Tendeka, prepared for the 2010 SPE Intelligent Energy Conference, Utrecht, The Netherlands, 23-25 March.

Passive inflow-control devices (ICDs) are used to enhance the performance of horizontal producing wells in unfavorable environments such as nonuniform permeability and/or pressure variations along horizontal sections. ICDs were combined with a fiber-optic distributed-temperature-sensing (DTS) system to manage the water-injection profile across a reservoir horizon. This field trial demonstrated the effectiveness of the ICD system when used for injection-well profiling and for fluid diversion during acid stimulation.  

Introduction

To understand the injection profile and well performance, a DTS system was deployed with ICDs and swellable packers as a field trial in a planned injection well. The objectives were to provide real-time information on multirate testing, determine real-time compartmental-injection profiling, and eliminate the need for horizontal flowmeter logging and well intervention.

Recent designs use ICD-completion technology with a DTS umbilical deployed in the openhole producing section below a liner for real-time monitoring and controlling of inflow from each compartment, thereby extending well life and increasing recovery. This case involved the use of DTS and ICD technology to control injection profiles in an openhole near-horizontal well. Compartments were created by use of water-swellable packers with feedthrough capabilities for the DTS umbilical.

Completion Design

The reservoir section was separated into six compartments. On the basis of openhole-log analysis, the reservoir has a uniform porosity along the length of the well, with a few dolomite intervals present. The spacing of the ICDs and packers was planned in such a way as to isolate these dolomite sections while distributing the desired injection rate along the well. To mitigate the risk of getting stuck while running the lower completion to total depth, it was decided to limit the number of openhole packers to six, thereby reducing the number of allowable compartments.

DTS System and Installation

The DTS and a permanent downhole-monitoring system were installed in April 2009. The fiber-optic DTS cable was attached and secured to the production-tubing string and provides multipoint temperature profiles across the length of the well. The real-time data from the DTS system can be used for injection optimization and reservoir management by monitoring injection rates between and within the ICD compartments and by identifying crossflow conditions.
Shale Holds Huge Potential for Researchers at Universities
Authors: Rassenfoss Stephen
Published: February 2015

A simple question, “Can you tell us about shale?” has spawned growing research programs at universities around the globe.

In less than five years, industry-supported university research has played a key role in defining the structure and elements in shale. The work in a group of laboratories at the University of Oklahoma (OU) in Norman, Oklahoma, is an example of the competitive drive to understand these challenging rocks.

Now the goal is to explain the inner workings of these rocks and use that understanding to find more oil and gas and produce it far more efficiently.

“The whole thing started with the question: Can you tell us about shale? It is leading into so many interesting areas,” said Chandra Rai, who along with Carl Sondergeld has led the OU lab at the Mewbourne School of Petroleum and Geological Engineering. The pair and a longtime lab manager moved into academia in 1999 when BP donated its petrophysics lab to the university.

At the time, shale exploration was often still seen as little more than an interesting experiment by Mitchell Energy Company in the Barnett Shale around Fort Worth, Texas. During the following decade:

The lab—renamed the Integrated Core Characterization Center—moved to OU’s main campus in Norman.

Devon Energy bought Mitchell Energy and showed that drilling horizontal wells could significantly increase shale gas production.

The industry mobilized to tap the enormous potential in unconventional reservoirs.

In 2004, Devon’s shale exploration team started seeking more outside advice.

“When we began to look at it, we realized we had some big questions about shale,” said Jeff Hall, vice president of exploration at Devon. On the list were: How does oil and gas move through the rocks to the wellbore? How can we better complete wells in this reservoir? There are big differences in production from well to well. Why is that?

Devon’s shale research led it down a meandering path. It started with a geophysical study that morphed into a geological study that raised engineering questions. Hall said, “We began to realize it is more complicated.”

To begin with, researchers had to find tools capable of looking into the structure of these extremely fine-grained mudstones. When they did, it was clear the name shale covered a variety of things. “People started with the idea that all shales were all the same,” Sondergeld said. “It is amazing when you see the microstructure how different they are.”

Other companies and universities followed a similar path into shale research. The size of the resource, and the work needed to go after it, are both huge. From the start, the research indicated how unconventional shale reservoirs really are. As the list of questions grew, so did the range of experts involved.
Technical Talent Shortage Could Begin to Limit Growth
Authors: Rousset Jean-Marie , Bismuth Pierre , Soupa Olivier
Published: February 2015

Talent & Technology

How do you transition an industry from conservative and slow moving in terms of human resources (HR) strategy to proactive, responsive, and ready to take risk? This is the quandary facing exploration and production (E&P) companies at a time when a “big crew change” is under way. The industry will see a serious shortfall of experienced technical professionals from attrition in the coming five years when the call on technical expertise will be greater. An increasingly stringent post-Macondo regulatory environment and new frontier and unconventional oil and gas plays will leave companies struggling to maintain current operations and drive growth.

Schlumberger Business Consulting’s (SBC) annual Oil & Gas HR Benchmark survey provides information on trends involving petrotechnical professionals, namely geoscientists and petroleum engineers. Compiled from the responses of oil and gas companies and universities, the study has become a reference point for E&P executives seeking to understand industry trends and develop HR strategies that provide a competitive edge and sustainable business performance. The survey highlights best practices and gives insights into an often misunderstood and underestimated element of the global oil and gas industry: talent requirement.

The 2010 survey shed light on two important facts for the industry’s supply chain of talent: the demographic transition or “big crew change” is now taking place, and technical talent has become a true strategic enabler for delivering production and future growth.

Demographic Transition

More than 25% of petrotechnicals currently working for E&P companies are older than 50 years of age and the vast majority will retire in the next five years. This is the generation of professionals who joined the industry during the late 1970s and early 1980s at the peak of the oil and gas expansion cycle. The crisis of 1986 marked the brutal end of that expansion and the beginning of a long period of anemic recruitment that lasted nearly two decades and created an irreversible void in the ranks of today’s midcareer professionals. The vigorous upcycle of 2003 to 2008 has provoked a rapid and important uptick in graduate recruitment (a three-fold increase). This has finished shaping the sector’s demographic profile with its recognizable double-hump of young and senior petrotechnicals surrounding a gap of midcareer professionals (Fig. 1).
Coiled Tubing Operations From a Work Boat
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 141234, ’Coiled Tubing Operations From a Work Boat,’ by N. Long, SPE, Brunei Shell Petroleum, and R. Raj, S. Srisa-ard, SPE, and N.H. Son, SPE, Schlumberger, originally prepared for the 2011 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 5-6 April. The paper has not been peer reviewed.

Small offshore platforms have low deck-load capacity, and available deck space is insufficient for coiled-tubing (CT) workover operations. To find a solution to this issue, CT operations from a vessel were discussed and subsequently developed more than a decade ago. In 2002, the technique was refined substantially to improve safety and reliability, which allows well intervention from the deck of a floating anchored vessel. This technique uses a system that provides emergency CT disconnect and effectively compensates wave motion. 

Introduction

As with any mature oil and gas fields, maintaining and improving oil and gas production is considered part of production operations. Each year, Brunei Shell Petroleum typically selects a minimum of more than 60 wells as candidates for CT intervention. These candidates usually are distributed over 30 different offshore platforms. In terms of operational time, this intervention objective normally requires continuous activity for 7 to 8 months.

When studying the feasibility of conventional CT well intervention on a small production platform, there are normally three main issues to be examined. First, the platform deck area for placing equipment should be sufficiently large for placing CT equipment, pumping equipment, wireline equipment, and testing equipment, and for allowing equipment access spaces. Second, the platform crane must be able to lift equipment dynamically from a supply boat to the platform. Third, the production-platform structure must be strong enough to withstand the total weight of the CT equipment.

In Brunei, normally it is not feasible to place all the CT equipment on offshore production platforms because the decks of those platforms are too small. CT-intervention-work targets on three-leg platforms and four-leg platforms that have available deck space range between 214 and 1,905 ft2. The maximum deck loads corresponding to these areas are in the range of 19 to 173 t. The installed crane on these platforms is primarily for lifting small loads, which are needed to support production operations. Therefore, the dynamic crane capacity is usually less than 5 t, and its boom length is approximately 15 ft.

CT well-intervention work commonly includes wellbore cleanout, wellbore mechanical-obstruction retrieval, sand control, adding perforations, and matrix acidizing. To cover all these types of work, the deck-space requirement for setting up equipment should be at least 3,500 to 4,000 ft2 (or more) and deck-load capacity should be between 170 and 270 t.
Radio Frequencies as an Oil-Production Stimulation Method
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 133085, ’Quantum Effects Imparted by Radio Frequencies as a Stimulation Method of Oil Production - Part II,’ by J. Mike Brown, SPE, Harold L. Becker, and Greg Darby, SPE, BJ Services, prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. The paper has not been peer reviewed.

Tuned energy waves alter molecular bonds in the well-tubular and near-wellbore regions to stimulate production by disrupting damaging deposits and altering relative permeability. New studies elucidate the action mechanism and the range of the application.

Introduction

The full-length paper is a continuation of paper SPE 124144 in which a method of stimulating producing wells by use of electromagnetic frequencies was described. The frequencies used by the device are in the range used in nuclear-magnetic- and electron-spin-resonance spectroscopy. The mode of action is thought to be the result of changing the nuclear- and electron-spin states of molecules such as paraffin waxes and altering the degree of hydrogen bonding and charge induction that allow aggregation and networking of the wax particles.

A recent study of the process provided additional insight to explain the action mechanism and to aid candidate selection. Laboratory core-flow studies showed that wettability reversal can increase production by removal of production impairments. Not all treated wells have shown measureable increases in production, and additional work is needed to improve candidate selection. Some wells that did not show a production increase benefited in reduction or elimination of workover and conventional chemical treatments. The electromagnetic frequencies used in this iteration of the device target near-wellbore damage resulting from wettability changes caused by hydrocarbon-based deposition or past production practices that resulted in this type of damage. These frequencies are in the radio-frequency (RF) band of electromagnetic radiation.

Relative Permeability Modification

Core-flow studies on native oil-wet sandstone were conducted to evaluate the effect of RF treatment on the relative permeability of oil and water. During core preparation, differential pressure and flow rate were monitored to calculate effective permeability to oil at irreducible water saturation (KoSwi). The sample was unloaded from the core holder and transported to a laboratory RF unit for treatment. Following a 15-minute RF-treatment period, the sample was reloaded into the core holder at 180°F. Alternating cycles of mineral oil, 2% KCl, and then mineral oil again were injected. Differential pressure and flow rate were recorded and the permeability was calculated. The sample was unloaded from the core holder and subjected to a second 15-minute treatment. The sample was reloaded into the core holder at 180°F and alternating cycles of mineral oil and 2% KCl were injected. Differential pressure and flow rate were recorded, and the permeability was calculated.
Corrosion Control of Drilling Tools Through Chemical Treatments
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 130515, ’Corrosion Control of Drilling Tools Through Chemical Treatments - Effectiveness and Challenges,’ by Nausha Asrar, SPE, Schlumberger, originally prepared for the 2010 SPE International Conference on Oilfield Corrosion, Aberdeen, 24-25 May. The paper has not been peer reviewed.

Increasing production is challenging because the wellbore fluids in many new fields are typically multiphase with harsh chemical compositions and conditions, such as high hydrogen sulfide (H2S), carbon dioxide (CO2), and occasionally dissolved oxygen, in a high-temperature/high-pressure environment. All this makes corrosion control a major concern, especially in the present challenging economic climate, where the risks and cost associated with corrosion may have significant impact on health, safety and the environment; on capital expenditure; and on operation expenditure.   

Introduction

Domestic oil and gas production is considered a mature industry in the USA because most of the significant available reserves have been identified and are being exploited. Direct corrosion costs associated with this activity are estimated to be approximately USD 1.4 billion, with USD 0.6 billion attributed to surface-piping and facility cost, USD 0.5 billion to downhole tubing, and USD 0.3 billion to capital expenditures related to corrosion.

Corrosion is defined formally as the destruction of metal by direct chemical reaction or by an electrochemical reaction of a metal with its environment. Chemical corrosion is the direct combining of a metal with another material, and it usually occurs at higher temperatures. Corrosion of this type seldom occurs in drilling, except in very-high-temperature wells. The second, more common type of corrosion electrochemical, occurs at a solid/liquid interface. This arises in nearly every instance where water or brine contacts metal/alloy equipment. Therefore, electrochemical corrosion is the principal concern in drilling operations.

Drillpipe probably is the most harshly treated of all equipment at the rigsite. While a well is being drilled, the drillpipe is exposed to high stresses, and it is exposed to both formation fluids and drilling mud. Thick-walled drillpipes are called drill collars. They contain electronic chassis and other measurement tools on the annular side and provide weight to the bit for drilling. These drillpipes are made of hardened high-strength steel and are likely to suffer from fatigue and different types of corrosion started from deep corrosion pits caused by corrosives, either from the mud itself or from being stacked wet. Also, the high hardness and strength of the drill-collar materials makes such collars more susceptible to stress corrosion cracking (SCC).

Corrosion Mechanisms

Corrosion encountered in drilling operations involves several mechanisms that have been grouped into (1) electrochemical corrosion, and (2) mechanical/corrosive effects.
Technology Focus: EOR Operations (June 2011)
Authors: Bonet-Cunha Luciane
Published: February 2015

Technology Focus

Enhanced oil recovery (EOR) is not new. There are many areas of the world where most of the oil is produced by use of EOR techniques. Among possible options, the predominant EOR methods in use to recover oil left behind are thermal, CO2-injection, and chemical-injection methods. However, despite many developments and successful implementations, EOR is still risky. Well-known areas for technology development that will boost EOR-project results include robust reservoir modeling, reliable reservoir-surveillance/-monitoring technologies, and efficient operations to minimize operational costs.

Regarding technical publications, during the past year, more than 350 papers with the main focus on EOR were presented at various SPE events. Topics explored in several of them relate to enhancements associated with the three key areas mentioned above. One new important point described in many papers refers to extending the use of smart-field technologies to EOR, aiming at continual optimization of oil and gas production in a certain field. To achieve this optimization, it is imperative that data gathered in the operational phase be applied to improve the quality of the associated reservoir models used for management in a fast and reliable manner, leading to so-called closed-loop reservoir management.

This month, the featured papers address many challenges found in EOR operations. Papers selected present interesting and successful field-development projects under way throughout the world. Also emphasized is the importance of bringing in and applying novel ideas, such as the smart-field concept, to solutions of EOR challenges.

EOR Operations additional reading available at OnePetro: www.onepetro.org

SPE 132626 • “Ensemble-Based Optimization of EOR Processes” by Uchenna O. Odi, SPE, Texas A&M University, et al.

SPE 132774 • “Improved Polymer-Flood Management Using Streamlines” by Torsten Clemens, SPE, OMV, et al. (See SPE Res Eval & Eng, April 2011, page 171.)

SPE 139851 • “Tengiz Sour-Gas-Injection Project” by Sabyrzhan Darmentaev, SPE, Tengizchevroil, et al.