bluuebunny/crossref_metadata_2025 huggingface dataset:
Links Between the Police Response and Women’s Psychological Outcomes Following Intimate Partner Violence
Authors: Srinivas Tejaswinhi , DePrince Anne P.
Published: February 2015

Virtually no research considers the psychological impact of institutional support for survivors of intimate partner violence (IPV). This study sought to fill this gap by examining associations between one component of institutional support—the police response—and posttraumatic stress disorder (PTSD) symptom severity and posttrauma appraisals (i.e., anger, fear, and self-blame) in a diverse sample of female IPV survivors (N = 236). Results indicated that a more negative police response, as operationalized by women’s unmet expectations in relation to the police, was significantly associated with greater PTSD symptom severity in a very conservative test that involved controlling for personal resources and social support. Police response was not significantly associated with the tested posttrauma appraisals. Implications for policy and practice will be discussed. This study advances understanding of the psychological impact of the police response—one key component of institutional support.
EMDR Group Therapy With Women Who Were Sexually Assaulted in the Congo
Authors: Allon Michel
Published: February 2015

Every year, thousands of women are sexually assaulted in the Democratic Republic of the Congo. In 2008, the author was invited to the Democratic Republic of the Congo to assist in developing and evaluating a brief psychotherapeutic approach that could be used to effectively treat sexually assaulted women suffering from posttraumatic stress. In this field study, 37 women were assigned to receive either 2 sessions of individual therapy (n = 8) using eye movement desensitization and reprocessing (EMDR) or 2 sessions of group therapy (n = 29) using the EMDR Integrative Group Treatment Protocol (EMDR-IGTP). Results of the study showed significant improvement in scores on the Subjective Units of Disturbance (SUD) Scale. SUD scores of those receiving individual therapy showed a significantly larger decrease than scores of the group therapy participants. All women completed the Impact of Event Scale (IES) before treatment, with scores well higher than the cutoff for posttraumatic stress disorder. Women (n = 6) in the first of the 4 EMDR-IGTP groups also completed the IES measure 2 weeks after treatment completion, with a significant decrease in their scores. In addition, many of the women spontaneously reported elimination of painful body sensations after the therapy. This study suggests the value of further research and development.
EMDR Adjunctive Therapy at a Community Agency, Treating Clients With a Spectrum of Mental Health Disorders
Authors: Czyz Ben , Muhlbauer Cyndi
Published: February 2015

This clinical practice article describes how to provide eye movement desensitization and reprocessing (EMDR) as an adjunctive treatment. It outlines the process used in developing an EMDR adjunctive therapy program in a nonprofit community agency that serves clients with chronic mental health and substance abuse disorders. The chronicity of clients’ mental health issues is complicated by life stressors that contribute to the lack of insight and accompanying poor decision making and helps to perpetuate the cycle of poverty and homelessness many experience. This article describes the initial pilot project in which EMDR was provided as a short-term intervention adjunctive to cognitive behavioral therapy, transactional analysis, and dialectical behavioral therapy. Preliminary results of this feasibility study supported the hypotheses that EMDR adjunctive therapy would reduce symptoms of traumatic stress and possibly enhance the effects of the primary therapy. This article makes multiple recommendations for program organization, including staff workshops and communication, and describes clinical strategies to ensure client readiness and to integrate EMDR with the other treatments. Recommendations are made for future research.
Understanding and Treating Narcissism With EMDR Therapy
Authors: Mosquera Dolores , Knipe Jim
Published: February 2015

Narcissistic personality disorder and narcissistic trait disorder are associated with selfish behaviors and lack of empathy toward others. Clients with either of these initial presentations in therapy show a self-centered profile and lack of empathy or concern about the suffering they may cause in other people, but this is only part of the picture. Sometimes the lack of empathy and selfishness is only a defense. To fully understand this problem, it is also necessary to be aware of underlying self-definition issues that drive the behavioral manifestations of narcissism. As in any psychological problem, eye movement desensitization and reprocessing treatment needs an understanding of how early experiences lead to future symptoms. Understanding the pathways from early experiences to narcissistic features (including covert presentations) is essential for an adequate case conceptualization as well as comprehending the defensive mental structures that impede accessing the core adverse experiences underlying the symptoms.
EMDR With Choking Phobia: Reflections on the 2008 Study by de Roos and de Jongh
Authors: Myers Keith J.
Published: February 2015

“Translating Research Into Practice” is a regular journal feature in which clinicians share clinical case examples that support, elaborate, or illustrate the results of a specific research study. Each column begins with the abstract of that study, followed by the clinician’s description of their own application of standard eye movement desensitization and reprocessing (EMDR) procedures with the population or problem treated in the study. The column is edited by the EMDR Research Foundation with the goal of providing a link between research and practice and making research findings relevant in therapists’ day-to-day practices. In this issue’s column, Keith J. Myers references de Roos and de Jongh’s study, which investigated EMDR treatment of choking phobias. Illustrating the treatment considerations and treatment results reported by de Roos and de Jongh, Myers describes the successful treatment of an adult client who presents with choking phobia and secondary depression using the EMDR protocol for phobias. The case example is followed with a discussion of specific treatment considerations in the addressing phobias within the eight phases of EMDR therapy.
Topical Treatments Used by Breastfeeding Women to Treat Sore and Damaged Nipples
Authors: Buck Miranda L. , Amir Lisa H. , Donath Susan M.
Published: February 2015

Background: Nipple pain and trauma are frequent complaints of new mothers, and a variety of treatments have been proposed and investigated for efficacy. Numerous studies have examined the efficacy of nipple creams, but there is no published data describing patterns of use in
breastfeeding women.

Aim: To describe the use of topical nipple treatments by a cohort of first-time mothers in Australia

Methods: A cohort of 360 nulliparous women were recruited in Melbourne, Australia, and the question, “In the last week, have you used any creams
or ointments on your nipples?” was included in a questionnaire on breastfeeding practices administered at 6 time points.

Results: In the first week after giving birth, 91% (307/336) of women used a topical treatment on their nipples. The most popular treatment was purified
lanolin, with nearly three quarters of women (250/336) reporting its use. At 8 weeks postpartum, 37% (129/345) continued to use topical treatments, and 94% (320/340) of women continued to breastfeed.

Conclusion: Widespread use of topical nipple creams is concerning not only because
it may indicate a high rate of nipple pain but also because this is a disruption to the natural environment where the newborn is establishing breastfeeding.
Increasing Sucker Rods' Working Capacities
Authors: Telli Francisco Diaz
Published: February 2015

Technology Update

Artificial lifting systems are being pushed to their operational limits, given the more demanding field operating conditions that require deeper wells and higher production flows. Over the years, the number of secondary-recovery and nonconventional oil projects has increased, and more is being asked of rod pumping (RP) and progressive-cavity pumping (PCP) systems.

Both pumping systems have found the sucker-rod string to be one of their weakest links. Stress analysis and failure statistics for different parts of sucker rods have found the weakest point to be located in its coupled connection. Rod-pin and coupling failures have become common problems in fields, making it clear that the fatigue resistance of the connection is inferior to the fatigue resistance of the rod body.

Several potential solutions designed to increase rods’ working capacities have been attempted, but none of them attacked the problem genesis: the connection. Recently, however, a premium-connection rod has been developed with a new thread design that has demonstrated very positive results in reducing connection fatigue (Fig. 1).

Design Process

Finite element analysis (FEA) is a numerical tool used to verify designs before field testing can be performed, and with FEA, the most significant design constraints of conventional rod connections were analyzed as a basis for developing the new premium connection design.

The main points addressed in the development of the new design were the following:

Loosening tendency of the connection because of a gap between threads. This gap allows movement between coupling and pin threads when rods undergo compression and/or shocks.

Permanent deformations of the thread (as verified by FEA) during makeup and well operations. These deformations make crack propagation more likely. They also result in a difficult makeup operation when repeating displacements.

Nonuniform stress distribution in thread profile generates regions of high stress concentration and, as a result, makes the pin and coupling more susceptible to the appearance of cracks (also verified with FEA).

High reliance on the makeup operation because both overtorque (increase in the stress level) and undertorque (stress concentration during well operation) are harmful for the connection and produce failures in sucker-rod pins and couplings. In conventional design, thread effectiveness is highly dependent on the cleaning operation before the string is run into the well and an inefficient makeup can easily result and later produce failures.
Technology Focus: EOR Performance and Modeling (January 2010)
Authors: Bai Baojun
Published: February 2015

Technology Focus

The demand for oil continues to grow, and it is forecasted that oil will continue to dominate the world share of energy supply for the next 3 decades. Accordingly, new discoveries tend to decrease on an annual base, and enhanced oil recovery (EOR) has the potential to reclassify unrecoverable and contingent reserves. EOR is viable because there are many available mature technologies, its implementation usually does not require drilling and completion cost, and most of the existing infrastructure can be used. 

When I selected the EOR papers to highlight this year, I classified the papers into the categories of gas injection, chemical methods, thermal methods, conformance control, microbial EOR, carbonate-reservoir EOR, reservoir-problem-identification technologies, and novel EOR methods including low-salinity waterflooding, imbibition EOR, alkaline/surfactant/gas injection, and CO2-miscible combined with alkaline/surfactant/polymer injection. Not surprisingly, CO2 EOR and polymer floods have drawn great interest this last year because CO2 sequestration has been a great interest to the community and polymer flooding is a proven cost-effective chemical-EOR method. The published polymer papers cover mainly the topics of thermal-stability evaluation of different polymers, novel polymer-flooding modeling, polymer-rheology database, and the formation effects on polymer properties. The CO2 publications discussed mainly the feasibility-evaluation results of CO2-EOR projects in different oil fields worldwide.

An EOR project is not just a matter of injecting materials, with many factors affecting whether the project is successful. The design and implementation of an EOR project require a systematic integration from a multidisciplinary team. It is critically important to identify the problems of mature oil fields for a successful EOR project, and, thus, the papers to identify channels in mature oil fields were included in this EOR feature.

EOR Performance and Modeling additional reading available at OnePetro: www.onepetro.org

SPE 121460 • “Stability of Partially Hydrolyzed Polyacrylamides at Elevated Temperatures in the Absence of Divalent Cations” by R.S. Seright, SPE, New Mexico Institute of Mining and Technology, et al.

SPE 123971 • “Streamline-Based Simulation of Non-Newtonian-Polymer Flooding” by Abdulkareem M. AlSofi, SPE, Imperial College—London, et al.

SPE 123930 • “Identification and Characterization of High-Conductive Layers in Waterfloods” by C.S. Kabir, SPE, Hess, et al.

SPE 124930 • “Mechanistic Modeling of Emulsion Formation and Heat Transfer During the Steam-Assisted Gravity-Drainage (SAGD) Process” by Prince N. Azom, University of Texas at Austin, et al.

SPE 124946 • “Pore-Level Mechanics of Forced and Spontaneous Imbibition of Aqueous Surfactant Solutions in Fractured Porous Media” by Amar J. Alshehri, SPE, Stanford University, et al.
Industry Experience With CO2-Enhanced-Oil-Recovery Technology
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 126446, ’Industry Experience With CO2-Enhanced-Oil-Recovery Technology,’ by R.E. Sweatman, SPE, Halliburton; M.E. Parker, SPE, ExxonMobil; and S.L. Crookshank, American Petroleum Institute, prepared for the 2009 SPE International Conference on CO2 Capture, Storage, and Utilization, San Diego, California, 2-4 November. The paper has not been peer reviewed.

This summary shows how the oil/gas industry has achieved success in engineering the process to capture, transport, and inject CO2 in enhanced-oil-recovery (EOR) projects. Some 37 years of safe and environmentally friendly large-scale operations, lessons learned, technical advancements, and millions of tons of CO2 injected demonstrate this success. With carbon capture and storage (CCS) being widely considered and with a few countries implementing commercial-scale CCS projects, technology transfer shares the experience of the oil/gas industry and the major contribution it can make as part of the solution for climate change.   

Introduction

Since the first CO2-EOR patent was granted in 1952, the oil/gas industry has spent many tens of billions of dollars developing and implementing CO2-EOR technologies, asset development, and operational experience. As new sources of CO2 have become available, field-testing and demonstration or pilot-project activities have been conducted. These development and improvement efforts have been continuous since the first project in 1964. The first large-scale, commercial CO2-EOR project began operations in 1972 at the SACROC field in west Texas, which is still in operation. Many more projects have started since that time, and by 2008, the count reached 112 projects. Innovative, cost-effective materials, equipment, and methods continue to be developed and implemented, such as the introduction of real-time smart-well operations at SACROC.

CO2-EOR Technology for CCS Deployment. Underground geological storage of CO2 is a promising technology for reducing greenhouse-gas (GHG) emissions because much of the technology developed by the oil/gas industry that is associated with natural-gas processing and CO2 EOR can support the sound implementation of CCS. Large storage capacity exists in deep saline formations, depleted oil/gas reservoirs, and unmineable-coal seams. According to a report in 2005 by the Intergovernmental Panel on Climate Change, as much as 55% of a worldwide GHG-mitigation effort through 2100 could be achieved safely by use of CCS.
Reservoir-Management Practices in the Offshore Oil Fields of Saudi Arabia
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 20123, ’Reservoir-Management Practices in the Offshore Oil Fields of Saudi Arabia,’ by Hassan B. Al-Qahtani, SPE, Phillip Warren, SPE, Ali M. Al-Shahri, SPE, and Abdulrazzaq Al-Muhaish, Saudi Aramco, originally prepared for the 2009 Offshore Technology Conference, Houston, 4-7 May. The paper has not been peer reviewed.

Challenges associated in developing mature offshore fields of Saudi Arabia require the optimal integration of best reservoir-management practices. A variety of practices was implemented to achieve significant improvements in drilling and completing horizontal wells. Some of these challenges have been addressed with the installation of more than 200 inflow-control devices (ICDs) to minimize water-coning and gas-cusping affects. Economic development of these offshore projects has involved the implementation of 20 smart wells, in conjunction with intelligent-field monitoring.  

Introduction

The developed offshore fields (M, Z, and S) of Saudi Arabia are in the Arabian Gulf and consist of sand-stones, siltstones, and shales with minor limestones and coals deposited in a complex, fluvial-dominated delta system. The main producing reservoirs consist of massive, clean highly permeable sandstone units interspersed with shales. The primary drive mechanisms for all three fields result from natural-aquifer influx with limited support from gas cap expansion in two fields.

Reservoir-Management Practices

The reservoir-management philosophy in the offshore environment is to maximize the economic recovery of oil and gas reserves while meeting production demand targets. In addition, the Saudi Aramco strategy offshore is to minimize water and gas production to avoid adverse effects on the facility infrastructure. Hence, best-in-class reservoir-management practices and innovative technologies were adopted in offshore fields to mitigate some of these concerns. The successful practices and technologies used to achieve significant improvements in drilling and completing horizontal wells in very complex reservoirs include

Measurement while drilling (MWD)/Gamma ray (GR)

Advanced geosteering/well placement

ICDs

Interval control valves (ICVs)

Smart dual-lateral wells

Smart in-situ gas lift systems

Permanent downhole monitoring systems (PDHMSs)
Elgin/Franklin: What Could Have Been Done Differently?
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 123681, ’Elgin/Franklin: What Could We Have Done Differently?,’ by Eric Festa, Total E&P UK, originally prepared for the 2009 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 8-11 September. The paper has not been peer reviewed.

At the time of project sanction in 1997, Elgin/Franklin was the largest high-pressure/high-temperature (HP/HT) development in the world.  It required innovation across the full range of operator activities. Eight years after production began, it is fair to say that Elgin/Franklin has not only achieved the aims of the initial project, it has clearly surpassed them. With hindsight, using this experience, combined with a decade of further progress in technology, some Elgin/Franklin-development features could have been optimized further.  

Introduction

The Elgin and Franklin gas/condensate fields were discovered in 1991 and 1986, respectively, in the Central Graben area of the North Sea. The reservoirs are 5500 m deep and present abnormally high pressures (1100 bar), extreme temperatures (200°C), and significant levels of carbon dioxide and hydrogen sulfide. Facilities consist of two wellhead platforms, one normally unattended (Franklin) and the other located over the Elgin field. Glenelg and West Franklin are two HP/HT discoveries made after the initial development of Elgin/Franklin that were put on production in 2006 and 2007, respectively.

Initial Field Development

Field-Development Plan—1997. The development was based on 12 wells (seven on Elgin, five on Franklin) and included the recovery of two predrilled appraisal wells. Provision was included for a second Elgin wellhead platform, also bridge connectable to the process-utilities and quarters (PUQ) platform, to be installed later if warranted. The project included the installation of a normally unmanned wellhead platform on the Franklin field, with Franklin production transferred to the Elgin permanently manned PUQ platform by means of a multiphase interfield pipeline system (Fig. 1). The total estimated cost for the project represented a large investment, especially in the low hydrocarbon-price environment prevailing at the time.

The Elgin/Franklin project distinguished itself from other offshore installations in the UK continental shelf in that gas processing on the PUQ was designed to yield commercial-quality gas, satisfying both the Interconnector and National Transportation System specifications. On arrival at Elgin PUQ, the high temperature of the production demanded special cooling equipment. Titanium compact heat exchangers (CHEs) were selected because of their reduced weight compared to conventional shell and tube coolers.
Comments: Unconventional Access
Authors: Donnelly John
Published: February 2015

Editor's column

PTT Exploration and Production’s (PTTEP) agreement with Statoil to take a share of a Canadian oil sands development is just the latest in a string of deals by Asian oil companies made to gain access to unconventional resources in North America. Firms from China and India bought into projects throughout 2010 looking to gain access to new reserves as well as to gain technical knowhow.

Thailand’s PTTEP acquired a 40% interest from Statoil Canada in the Kai Kos Dehseh Oil Sands Project in western Canada in late November for USD 2.3 billion for its debut in the oil sands market. Statoil will keep the remaining 60% of the project. Kai Kos Dehseh has estimated reserves of 4.3 billion bbl and, using steam-assisted gravity drainage (SAGD), is on target to reach early production of 10,000 b/d in the first quarter of this year. Peak output is projected to be 300,000 b/d, which would help PTTEP move toward its goal of more than tripling current production to reach 900,000 BOEPD by 2020. “This acquisition provides the company access to a highly attractive oil sands deposit in Canada and a strong platform for future growth into unconventional resources,” the company said in a statement.

This follows deals by China firm Sinopec to buy ConocoPhillips’ stake in oil sands producer Syncrude Canada, China Petrochemical Corp.’s purchase of Calgary-based Addax Petroleum, and PetroChina’s buy-in of a stake in Athabasca Oil Sands’ MacKay and Dover oil sands projects. China first began buying small stakes in oil sands projects in 2005. 

Asian state oil companies are investing billions of dollars in oil sands projects in Canada and shale plays in the US. The goal is to secure new resources to fuel their booming economies and to learn the techniques and technologies that will help them develop unconventional resources in their own backyards. With oil prices steady above USD 70/bbl, SAGD oil sands projects remain economic and, with gas prices still depressed, independent producers are welcoming the infusion of Asian cash. Shale developments in North America have attracted a string of deals over the past 2 years, the latest being Chinese National Offshore Oil Corp.’s purchase of a one-third stake in Chesapeake Energy’s Eagle Ford shale acreage in south Texas in November.

Although reserves estimates for Asia’s unconventionals potential are sketchy, the International Energy Agency puts China’s unconventional gas reserves at 144 trillion cm. Some analysts believe that figure is much higher. Last August, China inaugurated a shale gas research center and set goals of locating 1 trillion cm of recoverable shale gas reserves, building 15 billion cm to 30 billion cm of production capacity, and producing  8% to 12% of China’s natural gas needs from shale by 2020. The US government is also encouraging China’s development of shale in hopes that it will help the country cut carbon emissions.
Upgrading Formation-Evaluation Electronics for High-Temperature Drilling Environments
Authors: Dirksen Ron
Published: February 2015

Technology Update

Globally, increasing amounts of hydrocarbon resources are being found in fields that have very high thermal gradients. (It gets hot very quickly as you move downward.)

On the drilling side, challenging, high-pressure/high-temperature (HP/HT) wells customarily have been drilled with the simplest of tools, such as turbines and mud motors, which have minimal electronics and make no measurements. Logging-while-drilling tools, which do contain electronics and require electrical power to operate, have not been used thus far in these wells.

Most formation-evaluation tools have lots of electronic components, and so initially couldn’t be used in HP/HT wells. However, these wells are often located offshore, where high rig rates force operators to look for all possible means to increase drilling efficiency and optimize wellbore placement for maximum production.

Meeting HT Challenges

The main challenges in these environments are preventing the electronics from becoming damaged, maintaining measurement accuracy and precision, and generating or supplying the regulated power to the electronics reliably over the duration of the drilling effort.

Several parallel technologies have been developed over the past 5 to 6 years that can be used on their own or in combination to address these issues. The technology developments have concentrated on three main themes: HT electronics and the operating environment, new sensor technologies and measurement methodologies to improve accuracy and precision, and active cooling.

In this connection, a 2-year project to develop measurement-while-drilling tools that can record and transmit data at temperatures of 230°C—running for 14 days continuously—has been initiated by Halliburton. The purpose of this project was to finalize some of the ongoing developments in high-temperature electronics and sensor technologies and package them into a tool capable of performing in this environment.   

In considering the operating life of electronics, one of the main issues in HT environments is the increased rate of chemical reactions that cause the electronics to fail. In 1889, Svante Arrhenius documented the fact that chemical reactions require activation energy to proceed. The Arrhenius equation provides the quantitative relationship between temperature and the rate at which a chemical reaction occurs. This relationship is important for our industry because it governs many of the failure mechanisms for downhole electronics. 

The rate of chemical reactions is defined by the equation

K=Ae–Ea/RT,

which documents the exponential relationship between rate (K) and temperature (T). Ea is the activation energy for a particular process, and this value can be changed (by adding catalyst or inhibitor). Ae (pre-exponential factor) and R (gas constant) are empirically derived constants. Many reactions double their rate every 10°C.
Nanosized Particles for Enhanced Oil Recovery
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 129933, ’Nanosized Particles for EOR,’ by Tormod Skauge, SPE, Sverre Hetland, Kristine Spildo, SPE, and Arne Skauge, SPE, Uni CIPR, prepared for the 2010 SPE Improved Oil Recovery Symposium, Tulsa, 24-28 April. The paper has not been peer reviewed.

Colloidal-dispersion gels (CDGs) have been used in enhanced oil recovery (EOR) to provide sweep improvement in reservoirs exhibiting an unfavorable mobility ratio. Coreflood results indicate an improved microscopic sweep or microscopic diversion by CDG. A new concept of EOR by improved microscopic displacement is defined as microscopic diversion. This method involves pore blocking and diversion of injection fluids.   

Introduction

In most successful field applications involving CDGs, oil production increased and the water/oil mobility ratio decreased. There are few systematic studies regarding the detailed mechanisms of the CDG process. Most studies focused on the propagation of CDG in porous media and the gelation process. The gelation behavior of CDG systems was studied, with the aim of understanding the performance of CDG with respect to in-depth permeability modification.

Recently, coreflood data were published that report improved microscopic displacement by use of pregenerated CDGs. The objective and properties of the conventional approach from the 1990s targeted mainly macroscopic-sweep improvement, while the more-recent approach with pregenerated colloid particles has defined two classes of CDG. Here, pregenerated colloid particles are in the range of 100 nm. These solutions also have been called linked-polymer solutions and attempt to improve the microscopic-displacement efficiency in addition to the macroscopic sweep.

The purpose of this work was to investigate mechanisms for microscopic diversion by comparing the oil-mobilization properties of inelastic nanosized silica particles with those of CDG. Nanosized silica particles provide an environmentally friendly alternative to polymer or CDG flooding, thus lowering the threshold for implementation, particularly in offshore environments. Oil mobilization was investigated in a series of Berea-coreflood experiments.

A porous medium is a complex structure of pore bodies and throats with a range of sizes. Any material dissolved or dispersed in water may adsorb onto the solid surface. When a polydisperse solution of particles flows through a porous medium, particles with a size larger than or equal to the throat size will be trapped. This mechanism, which leads to blocking of narrow pore throats by larger CDG particles, is known as mechanical entrapment or straining.
Redevelopment of the Cardium Formation by Use of Fractured Horizontal Wells
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 137737, ’Re development of the Cardium Formation Using Fractured Horizontal Wells: Res er voir-Engineering Perspectives and Early Case Histories,’ by E.N. Omatsone, M.A. Bagheri, SPE, and C.M.F. Galas, SPE, Sproule Associates; B. Curtis, Bonterra Energy; and K. Frankiw, Midway Energy, originally prepared for the 2010 CSUG/SPE Canadian Unconventional Resources & International Petroleum Conference, Calgary, 19-21 October. The paper has not been peer reviewed.

The full-length paper presents a brief review of the historical performance of vertical wells in the low-reservoir-quality areas of the Cardium formation and describes the effect of placing multistage-fractured horizontal producers in these areas. The paper deals with the redevelopment of the Cardium formation from a primary-recovery perspective only, with a focus on the fringe areas around the supergiant Pembina field, as well as the development of the largely untapped resource in the A Lobe of the Cardium in the Garrington/Caroline areas.

Introduction

The Cardium formation is regionally extensive, spanning an area of nearly 150 townships in central/southern Alberta. The formation has been described as a clastic wedge that prograded into the western interior seaway during Turonian-Coniacian time. Many sedimentological responses identified within the formation indicate that the sand accumulation took place in muddy and sandy inner- and outer-shelf, shoreface, lagoonal, tidal, estuarine, and coastal-plain settings.

This wide variety of depositional environments resulted in a diversity of lithofacies, multiple disconformities, paraconformities, and diastems of varying lateral extents. The predominant rock types in the Cardium are mudstone and sandstone with small, but important, conglomerate fractions. The Cardium deposits formed a series of stratigraphic traps, the largest of which is the supergiant Pembina field in central Alberta. Cardium reservoirs and pools have been found at depths ranging between 1200 and 2800 m and typically contain light, sweet oil with varying amounts of dissolved gas. A number of rich-gas pools also can be found in the Cardium formation.

Operators who target the Cardium formation frequently are the beneficiaries of excellent core data, as a result of the standard industry practice of the 1950s through the 1980s. In the broader Pembina area, the Cardium exhibits exceptional log resolution because of its relatively shallow depth of burial. Many of the logs in the Garrington/Caroline area are of an older vintage and of generally poorer resolution. The abundance of core-plug, well-log, and production-performance data from the more than 10,000 vertical wells that have targeted the Cardium allows for high-quality petrophysical analysis and detailed geological mapping. Some operators have begun to use 3D-seismic amplitudes and other geophysical attributes to study the reservoir quality and pore-fluid content in various portions of the Cardium.
Building a "New Normal" on the Bedrock of Risk Management
Authors: Craighead Martin
Published: February 2015

Guest editorial

Historically, our industry has been driven by a series of inflection points to re-examine best practices, technologies, or philosophies on how we conduct our business. The most notable of these have often been associated with tragedies such as the 1988 Piper Alpha disaster in the North Sea and, most recently, the Macondo disaster in the US Gulf of Mexico. Piper Alpha led to a wide-scale focus on health, safety, and the environment (HSE), fundamentally changing the way companies viewed safety, and led to orders of magnitude improvement in HSE practices. While the full impact of Macondo is only now being fully understood, it is clear that we will see a similar effect on the way we handle quality, competency, safety critical systems, and contingency planning.

In both of the incidents, external pressure precipitated the cultural or technical shift to a new operating norm, while the capabilities and technology for bridging the gap were available. Until we consider risk management and operational sustainability as business drivers and an equal part of our mission, we will never make the paradigm shift from a reactive to a proactive business model.

The industry’s goal should be an incident-free environment, but government regulation alone will not help the industry achieve that goal. The reservoirs our industry is targeting are more challenging, the environments are harsher, and the technology required is ever more complex. As an industry we must be willing to go far beyond what is regulated—we must fundamentally change the culture of our business to address risk management in our processes, our technology, our talent management, and our safety programs.

Consistent processes and procedures across our business are the foundation for this change. A common operating system not only ensures that we meet regulations in all areas where we work, but also establishes repeatable performance that takes us far beyond what is required. Generally, there is one best way to perform an activity, whether it is solving problems for our customers or developing new products and technology.

An operating system encompasses critical operation management systems and captures the latest information and best practices. Such systems are widely used in industries such as automobile and fast food. Of course, the challenges facing the oil and gas industry are more diverse and highly complex. However, in general, the companies that pay attention to every aspect of their business and work smarter to capture the true power of their intellectual property win in the market.
The Weight of the Mission
Authors: JPT staff _
Published: February 2015

Two things stand out about Expro’s Ax-s technology—it is capable and it is big. The scale of the device, whose name is pronounced “access,” shows the array of tools that may be called on to deal with production problems.

“The seven-year development project, which cost USD 200, produced a device that can be lowered on top of a wellhead with the brains of a remotely operated vehicle (ROV) capable of deploying any one of eight diagnostic and repair tools in minutes with a winch and tanks for glycol or other fluids needed on the job. When fully assembled, it stands at 110 ft high and weighs 237 tons.

Its competitors include companies such as Blue Ocean Technologies, whose Iris system is also certified to work in deep water. It weighs 25 tons, but it can only insert one tool at a time into the well. Change outs require pulling one tool to the surface and lowering another. All subsea wireline systems connect to the subsea trees with a well control package using valves and blowout preventers to contain what is inside the well.

(The term “tree” was coined when the flow control device consisted of a vertical pipe with hardware branching off of the trunk. Subsea wellheads are complex clusters of pipes, valves, and controls surrounded by a stout metal frame the size of a garage.)

The size differences show different design philosophies.

Expro designed its device to speed the work by offering a wider range of options, like a surgeon with an array of tools at hand to deal with the unexpected. Inside the pressure housing is a collection of eight tools, which can be altered to suit the job. An Expro illustration showed a diagnostic water tool, a cutting torch, a perforating gun, a plug, and a tractor to pull the strings through a horizontal well.

“Once it is on the well, it can change out wireline tools in 10 minutes,” said Matthew Law, technical manager of sales and marketing at Expro Ax-s Technology. “There are eight tools on board. It is more efficient than those with limited functions that must be pulled up to the surface to change out functions.”

He said the added speed of the work by the Ax-s, plus a day rate significantly less than drilling rigs, will allow workovers at one third the cost of a drilling rig.
Seeking the Lighter Side of Heavy Duty
Authors: JPT staff _
Published: February 2015

The weight of a deepwater riser requires a large vessel to bear the weight of the steel pipe running a mile or more from the surface to the ocean floor.

The Skandi Aker, which is equipped with a relatively small 7⅜-in. high-pressure riser for well maintenance and construction work, is more than 157 m long, about half the length of the largest cruise ships.

Innovators have taken on the challenge of building a riser that will allow smaller boats to do things now only possible with a rig or drillship. More than a decade of work has gone into solving the problem, and no one appears close to getting a product on the market.

Their motivation is the many people in the business who expect the added muscle that coiled tubing can provide when working on wells. “Oil companies want to be able, if they have a problem they have to get rough with, to have the equipment to get rough with it,” said Brian Skeels, emerging technologies director at FMC Technologies.

Several companies are looking for a way to use coiled tubing deployed off a construction vessel to deliver fluids to the well as a riser does. It would offer a conduit to the for jobs requiring fluids such as acid treatments. The challenge is to maintain enough tension on a pipe from a vessel that is rising and falling with the waves.

Baker Hughes is developing what it describes as a riserless coiled tubing intervention system. Unlike the riser, which provides a conduit for coiled tubing, this tubing would act as a pipeline carrying fluids directly into the well, said Lance Portman, vice president of coiled tubing and cementing at Baker Hughes. It could allow smaller vessels to do a greater range of work, for example, by delivering hydraulic fluids to power tools or acid to remove asphaltene.

“You have limited options with wireline. With coiled tubing, you have more options,” Portman said. The company developed a system to maintain the tension on the tubing with two devices: one on the boat to adjust for the heaving caused by the waves, and the other on the seafloor that maintains the tension on the tubing.

The project with Blue Ocean, which is providing the seafloor equipment needed to safely get the pipe into the well, is years away from having a system to sell.
Innovation: Innovative Drilling Operations
Authors: Imomoh Egbert
Published: February 2015

President's column

The first wells used to search for oil were drilled more than 150 years ago. Since then, various innovations have been adopted and adapted to enable us to drill deeper and deeper wells, with longer and longer reach, and in ever-increasing water depths, resulting in access to oil and gas reserves that have fundamentally changed the world. We have encountered various challenges over the years, but by seeking new ways of getting the bit down to the depth required in a safe manner, our industry has allowed billions of barrels of oil and trillions of cubic feet of gas to be produced for industrial growth and development. Those first wells were drilled with very basic tools. The floaters of today, drilling in thousands of feet of water, are clearly far advanced from the early efforts, which used a steam engine powered by a wood-fired boiler.

Edwin Drake is famous for his pioneering drilling work, and as with most innovators, he met head on with potential failure when he drilled his first well. Drake encountered losses and potential hole collapse that would have prevented him from drilling to his planned total depth. He is reported to have driven a surface pipe and then proceeded to drill and reach into deeper horizons. This fundamental principle of isolation has served the industry well and forms the basic design of wells drilled today. However, innovation has permitted some operators to drill through surface sections that present swelling problems that lead to premature setting of surface pipe, which in turn lead to delays in drilling operations and increased well cost. Some operators have successfully applied innovative casing-while-drilling techniques, which use large pipes as the drilling string. This technique allows the operator to minimize exposure of the wellbore to the drilling fluids and reach surface setting depth as planned (SÁnchez, Houqani, Turki, and Cruz. 2012).

The history of drilling is rich with innovations. They are too many to cover in one column, but I think two are noteworthy: the advances that permitted drilling in deeper and deeper waters and the development of mud motors.

The early move away from land operations took place approximately 120 years ago when wells were drilled from platforms that were constructed on piles in fresh water and then on piers in various areas offshore the US. As explorers found prospects in deeper and deeper waters, new technology was needed to drill from barges, artificial islands, or concrete barges. Today’s jackups and semisubmersibles are a far departure from the rudimentary equipment used for early offshore drilling.
Comments: The Long-Term Outlook
Authors: Donnelly John
Published: February 2015

Editor's column

Energy outlooks by companies, government agencies, and private industry groups identify long-term energy trends and develop projections on supply and demand based on factors such as technological advancement, population trends, the global economy, and policy issues. One of the most respected of these viewpoints comes annually from ExxonMobil, which last month updated its projections for the next 25-plus years in its “Outlook for Energy: A View to 2040.”

Although some of the trends are carry-overs from previous editions, the energy landscape has changed a lot over the past few years, most notably the growth in unconventional resources in North America. Here are some of the significant findings from the report:

Energy demand in developing nations will rise 65% by 2040, reflecting growing prosperity and expanding economies.

Greater demand in electricity and transportation fuel will help drive this increase.

Technology continues to allow for the development of once hard-to-produce energy resources, significantly expanding available supplies to meet global demand.

Oil will remain the top global fuel, as transportation use will contribute to gasoline and diesel demand. Demand for transportation fuel will stay flat in Europe and decline in North America, but it will grow dramatically in the rest of the world.

Natural gas will become the world’s second most used fuel during the period, overtaking coal.

ExxonMobil forecasts that global energy consumption will rise 35% by 2040, primarily in China and India. Demand in developed regions such as the United States, Canada, and Europe will largely remain unchanged or decline as they become more efficient in their energy use. Developed nations are forecast to generate 80% more economic output by 2040 compared with 2010, but will use the same amount of energy.

Another report released last month, by the US Energy Information Administration (EIA), predicts that growth in unconventional production will continue to have a huge effect on the US. The report forecasts US oil production increases of more than 200,000 B/D each year through 2019. In addition, the country will become an important supplier of natural gas globally as domestic production outpaces demand.

The US currently produces 6.5 million B/D of oil and that figure will rise to 7.5 million B/D by 2019, and will remain above 6 million B/D through 2040, according to the report. Most of the growth will come from onshore production, mainly from shale and other tight formations, the EIA said. US gas production will continue to out-strip domestic demand through 2020. The outlook sees world oil demand growing from the current 88 million B/D to 113 million B/D in 2040 because of strong consumption in China, India, Brazil, and other developing economies.