bluuebunny/crossref_metadata_2025 huggingface dataset:
The Role of Autonomous Flow Control in SAGD Well Design
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166266, ’The Role of Autonomous Flow Control in SAGD Well Design,’ by Sudiptya Banerjee, SPE, Robert Jobling, SPE, Tarik Abdelfattah, SPE, and Hang Nguyen, SPE, Baker Hughes, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed.

One notable improvement originating from recent field experience is the novel use of injection-/inflow-control devices (ICDs) in a conventional steam-assisted-gravity- drainage (SAGD) well pair. The use of a properly designed ICD completion has proved beneficial to the processes of developing the steam chamber and improving the inflow profile of the producing well of the SAGD pair. Work conducted in the Surmont field of Alberta, Canada, provided an excellent starting point to optimize flow-control improvements to the SAGD process.

Introduction

To obtain high efficiency, the SAGD process demands a high degree of steam conformance along the wellbore. The better the steam conformance, the greater the amount of oil mobilized and the higher the potential for oil recovery. However, conformance should not come at the cost of excessive steam injection.

A number of thermal inefficiencies (described in the complete paper) are unavoidable in the SAGD process. These collectively result in a deformed and nonoptimal steam chamber that undermines energy maintenance and lowers the ultimate recovery factor. By incorporation of flow-control devices (FCDs) into the injector or producer well, however, a more ideal, more desirable chamber shape can be realized.

Overview of ICD Geometries

Fundamentally, all flow-control devices operate by the same mechanism: They provide an additional pressure drop at select points in the completion string to complement the pressure drop of fluid moving through the reservoir as well as internal pressure drops within the completion itself. Despite this fundamental similarity, however, the methods by which different styles of ICDs create this pressure drop vary strongly with design.

There are three distinctive categories of passive inflow-/injection-control devices (PICDs) available today. The two most common PICD geometries are orifice/tube/nozzle-based (restrictive) (Fig. 1) and helical-channel/baffled- pathway (frictional) (Fig. 2). The restriction-based PICD uses fluid constriction to generate a differential pressure across the device. This method essentially forces the fluid from a larger area through small-diameter ports, creating flow resistance. A frictional-pathway PICD relies instead on surface friction to generate a similar pressure drop. These designs produce a distributed pressure drop over a relatively long area, as opposed to the instantaneous loss through a restriction-style PICD. When fluid flows through the channel/ channels, fluid rheology and channel characteristics interact to create the designed pressure drop.
Instantaneous 4D Seismic Used to Monitor Offshore Water-Injector Wells
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16901, ’Instantaneous 4D (i4D) Seismic: An Innovative Concept To Monitor Offshore Water-Injector Wells,’ by J.G.F. Stammeijer, M. Davidson, P.J. Hatchell, and J.L. Lopez, Shell, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. Copyright 2013 International Petroleum Technology Conference. Reproduced by permission.

In this paper, the authors propose a new method for time-lapse-seismic surveys focused on water-injector wells. The “instantaneous 4D” (i4D) method aims to acquire dedicated high-quality 4D data with a short turnaround time at cost levels low enough to make it affordable to repeat such data-acquisition programs reasonably frequently. We have implemented the method as a variation on surveys that use ocean-bottom seismometers. We suspect that our method can also be combined with other means of seismic-data acquisition (for example, permanent reservoir-monitoring systems and vertical-seismic-profiling systems in wells).

Introduction

Time-lapse, or 4D, seismic is frequently used offshore to monitor fluid-movement processes such as waterflood or aquifer drive. These processes happen at relatively slow time scales (years). As a result, proper monitoring of these effects requires repeat surveys to be acquired every 3 to 5 years or so.

Recent examples in industry show that fast reservoir changes (months) also are taking place. The observed changes are often associated with water-injector wells. For example, one water-injection well documented in the literature produced large time-lapse signals in less than 1 year after its startup. Because of cost and other considerations, it is not feasible to repeat fieldwide 4D surveys often, nor to install permanent monitoring systems in many of those fields. Yet there is a need to monitor such phenomena more frequently and with short reaction times. This is where the authors believe that the i4D method can play an important role.

This method is not intended to replace full-field surveys. Rather, it adds small surveys more frequently in between regular full-field surveys to enable better observation of fast 4D reservoir effects along with slow changes. It can be seen as filling the gap between the current practice of infrequent full-field surveys and the installation of permanent reservoir-monitoring systems, which can be expensive.
Comments: Looking Ahead (April 2010)
Authors: Donnelly John
Published: February 2015

Editor's column

Every year, IHS/Cambridge Energy Research Associates brings together some of the world’s top energy executives to Houston for a weeklong conference. The event acts as sort of a state-of-the-industry temperature check and spawns discussion about where the industry is now and where it is heading. Last year’s theme was surviving financial turbulence; this year’s reflected the sense of recovery both in the industry and world economies.

Amid the panel sessions and more focused breakout sessions, a general consensus arose about what may lie ahead for the oil and gas industry in the near future.

The recent highly publicized shale gas plays in the US have the potential to be one of the most significant developments in decades, and could decidedly change the industry—including markets and trade, investment, and supply/demand fundamentals. But this is not just a North American phenomenon—there is huge potential for unconventional-gas development in other parts of the world.

Thanks to the breakthroughs in shale production and global liquefied natural gas projects, gas can no longer be thought of as just a “bridge” fuel to future alternative energy.

Despite all of the talk of alternative energy sources the past few years, hydrocarbons will still be the major source of energy supply for at least the next 20 years and likely much longer.

Globalization of supply has existed for years, as producers around the world focused on key demand centers such as the US, western Europe, and Japan. But demand in these regions is peaking and the world is now witnessing a globalization of demand.

And the world will need all energy resources—hydrocarbons, nuclear, solar, wind, etc. to meet future world energy demand. There is no going back in the developing world as it moves toward a more energy-rich, more affluent, and more efficient economy and lifestyle.

Although global warming has lost policy momentum this year after the Copenhagen conference and controversy surrounding how some data were arrived at, the industry will continue to confront legislative and public concern over “climate change.” The march toward a lower-carbon future will continue, although many may not be aware of how difficult and expensive that transition will likely be.

The key to increasing supplies to meet growing demand lies in technology. The oil and gas industry certainly appears to be entering an era of transition. Oil supply growth appears to becoming more concentrated with only about a dozen or so regions with potential to grow, including Russia, Africa, Eurasia, and the Middle East. Demand growth has decidedly shifted to developing economies. And oil is now intertwined more than ever with financial and commodity markets as well as the climate debate, which will lead to not only the need for more transparency in the future but more regulation.
Techbits: Malaysia Workshop Highlights Production Enhancement
Authors: JPT staff _
Published: February 2015

Techbits

SPE highlighted the importance of maximizing production during economic downturns at the Applied Technology Workshop “Production Enhancement—Maximizing Production and Recovery in a Challenging Economic Climate.” The workshop, held in Penang, Malaysia in October 2009, brought together an international group of 91 participants to discuss and challenge the use of production-enhancement technologies.

The first keynote address by Ramlan Malek, vice president, E&P, Petronas discussed the importance of production-enhancement technologies such as improved-oil-recovery and enhanced-oil-recovery strategies in improving Malaysia’s recovery factor from the current 34–35% to more than 40%. His talk also addressed effective marginal-field development to increase and prolong peak production in Malaysia.

A second keynote address by Golden Energy Chief Executive Officer Mark Pearson discussed the role of engineers and practitioners in evaluating, applying, and benchmarking production-enhancement technologies. He also provided a historical perspective of the growth of hydraulic-fracturing technologies in the US for developing its abundant tight gas plays. He believes there is a revolution in hydraulic technologies led by multizone, staged fracturing; slickwater fracturing; and horizontal-well fracturing. These—together with the integration of microseismic mapping, reservoir visualization, and fracture-design models—are enabling technologies in the US unconventional-reservoir hydrocarbon development. 

Assessing Business Value Petronas’ Supply Chain Manager En. Suhaimi Yasin opened the first technical session with a discussion on strategies to address the new reality of lower hydrocarbon prices without a commensurate drop in costs for rigs and services. This market dynamic has caused Petronas to re-evaluate strategies to manage cost and value. Initiatives being adopted include strategic alliances on a risk/reward basis, longer-term contracts on a partner-ship basis, e-procurement, and better leveraging of technology.

Oddbjorn Skilbrei of Shell EPA discussed Lean Management Principles employed in Shell Malaysia assets to achieve breakthrough performance. The use of Lean Management Techniques has resulted in improved recognition of event triggers in well performance and reduced cycle time to fix the events. The group discussion emphasized the importance of accurate data gathering and team communication.

Feroney Serbini of Schlumberger closed the session with a case study on integrating surface network modeling with a reservoir model. The study benchmarked proposed solutions against the unconstrained model, and the selected solution provided a production increase of 1 million bbl more than the second best solution. The ensuing discussion focused on gaining further insight on the modeling methodology.
The First FPSO in the US Gulf of Mexico: The 14-Year Journey
Authors: Lovie Peter
Published: February 2015

Editor’s note: This is the first of two articles on the technical challenges and regulatory hurdles that were overcome to allow the use of floating production, storage, and offloading vessels (FPSOs) in the US Gulf of Mexico (GOM). The FPSO that will be installed at Petrobras’ Cascade-Chinook development in the deepwater GOM is planned for mid-2010 startup.

The practical start of the journey of the first floating production, storage, and offloading (FPSO) vessel to the US Gulf of Mexico (GOM) came in 1996, when an operator thought that an FPSO might be a viable candidate to efficiently develop a deepwater prospect.  Back then there were a number of FPSOs in operation in different parts of the world, so the idea was not revolutionary. Several conference papers at the time showed potential arrangements for an FPSO at Texaco’s Fuji development. As events unfolded, estimates of reserves were not as good as initially expected and the Fuji prospect was abandoned, but the idea of considering an FPSO in the GOM had taken hold.

During 1998–1999, Shell and its partner BP conducted feasibility studies for using an FPSO at its Na Kika development, involving study work by leading FPSO contractors. These studies were not just simple paper exercises, although traditional paper studies were made. Groups of facilities and subsurface experts met, examining every aspect of proposed candidates for field development and debating the pros and cons of solutions. Many in the industry may not appreciate the rigor of these debates unless you were in the middle of them. And in the middle of all this was a patient, objective participant, bringing out the best in everyone, George Rodenbusch of Shell (see sidebar).

Despite every consideration given to the FPSO option, all these debates and studies led to the conclusion that for the particular field at hand an FPSO was not the best solution, and today a semisubmersible is the centerpiece of the Na Kika development.

Again in 2000–2001 a supermajor looked exhaustively at the FPSO option but, weighing the regulatory uncertainties at the time and competitive pipeline economics, the FPSO and shuttle-tanker combination lost out to spars and semisubmersibles. About this time another development for another operator prompted presentations at an SPE lunch meeting in Houston showing shuttle tankers and an FPSO as the way to go. But that development became a tension leg platform (TLP), exporting via pipeline to produce that asset.

During this period some operators—often from outside the US—concluded that there was prejudice in the US against FPSOs, but the evidence of these repeated considerations of FPSOs over the years does not bear this out.  Regulatory expert Rick Meyer of Shell summed it up in a presentation at an SPE workshop in 2002: “Economics, economics, economics.” It was more a matter of just not having the right project for an FPSO in the GOM.
Drilling and Evaluation Technologies Extend Operating Limits in Challenging High-Pressure Deepwater Environments
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124324, ’Drilling and Evaluation Technologies Extend Operating Limits in Challenging High-Pressure Deepwater Environments,’ by Waitus Denham, SPE, Shell, and Brian Donadieu, SPE, Ernest Lee, SPE, Rohit Mathur, SPE, and Ananth Srinivasan, Baker Hughes, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October.

New drilling opportunities require technological innovations to increase efficiencies and optimize production. Some newer drilling operations, particularly in deep water, involve extreme environments such as ultrahigh pressures that require new approaches. With downhole pressures approaching 30,000 psi and escalating rig costs, rotary-steerable systems (RSSs) and advanced formation-evaluation technologies are needed.  

Introduction

Advances in rig design, in downhole tools, in data communications, and in other areas result from challenges associated with pushing and extending limits. While in the planning stages of a deep-water high-pressure well, risk mitigation and contingency planning are critical in making technology advances. It is important to balance the drive to advance technology with the value created.

Solution Potential

In many cases, wellbore construction can be accomplished with standard off-the-shelf products and services. When the location moves into deep water, the complexity, risks, and costs of those operations require fit-for-purpose or application-based solutions.

In this case, early in the design phase of the well, increased potential of a high-pressure situation was evident that would require equipment that was unavailable at the time. Therefore, the operator approached a selected vendor and began a feasibility study. Open communication between the companies was critical. After developing an understanding of the operator’s critical success factors, the service company gained clearer insight into the challenges at hand and was able to address the effects and risks associated with “new” technology.

Development Stage

Typically, well-construction planning involves a few key individuals from both companies. For this case, it was important to involve additional sup-port and expertise to ensure success. Expanded teams from the operator included the drilling, geology, and petrophysical disciplines, along with asset-management and offshore-operations experts. The vendor expanded its operations, applications-engineering, and technical-support functions to include reliability engineering, product development, quality management, repair, and maintenance.
En Route: The New Generation
Authors: Labastie Alain
Published: February 2015

President's column

During my various trips to visit SPE sections, I have on most occasions also met with students. I also had the opportunity to meet with groups of young professionals, mostly in dedicated workshops. These were very interesting and pleasant experiences.

All these young people are quite impressive. The way they are organizing their SPE activities and the initiatives they are taking denote more maturity than my generation exhibited at the same age. For them, SPE is really a prestigious organization, and they have fully understood how to take best advantage of what is offered by our Society. They are really open minded. To them, globalization is not just a concept; they have abolished many borders, and they want to establish contact across legacy borders. Last year, I attended a meeting in Poland that was organized by students for students from all our European student chapters. This experience was really wonderful—an intense exchange of ideas between students from Siberia to western Europe, with also very lively social activities. (This is important for students! Note that I did not join all of these.) These students fully under-stood that SPE forms a unique community, without borders.

When meeting with these students or young professionals, I noted some-thing interesting: the questions they are asking are almost the same everywhere. Typical questions are about how to start a career, technical vs. managerial careers, oil companies vs. service companies, and work/life balance. Our young professionals are really open to the outside world, to the Society. I believe that for them the image of the “industry hero” is somewhat different than for the older generations—their “industry hero” is somebody who is fully loyal to his/her company, but who no longer devotes all of his/her time and energy for his job, and who keeps some time available for social activities. As an example, many groups of young professionals and students are involved in charitable activities. I believe that this balance is excellent for the industry. The public’s perception of what is socially and environmentally acceptable is quickly changing and will play an increasingly important role in our activities. Having staff who are more attuned to societal issues will definitely help us to better understand public perceptions of our industry.

Another positive point is that this young generation includes a much higher proportion of women than in the past, which will certainly reshape our industry. Diversity—in cultural background, education, experience, and gender—provides different perspectives that can lead to greater innovation. Companies with a gender balance will have a clear advantage.
Shaped Charge Patents 1942-1952: From Optimism to Solutions
Authors: Atzmiller Noel
Published: February 2015

In the 1940s, the majority of research in America into shaped charge technology was performed by the US military and government laboratories. Information was largely classified. Shortly after the US Army declassified some details of this technology, extensive research and testing began in many American companies. Along with this came the filing of several patents. These US patents from the early years of shaped charge design reveal a transition from an almost naive optimism over the nascent technology to solutions for oilfield issues. A focus on the early claims and the issues with carriers and charge detonation reveals much in this regard.

The Early Years—Optimism and Uncertainty

A patent filed by E.I. du Pont de Nemours and Company in 1942 (2399211) typified the wave of optimism of shaped charge capabilities (this was not too unexpected, for du Pont manufactured the charges) (Fig. 1). Liners for the charges were not required, stated the document, but if they were present the metal slugs (“carrots”) produced from the detonation would be “projected at very high velocity through the perforation and into the adjacent strata.” In other words, the liner remnant was a positive consequence of the detonation. The patent also advocated the use of plastics or cardboard materials for the carrier, stating that the charge “may or may not be enclosed in a watertight container…they are generally insensitive to the action of water and impervious thereto.”

Two years later, another du Pont patent (2605703) described a “novel and improved explosive device.” The document provided many details about shaped charge liners, but admitted that an understanding of why the devices worked was unclear and speculated the penetration was due to “pulverizing, molecular fragmentation or abrasion.” Even the liner was considered a contributing factor in the “net destructive effect,” but the patent admitted it “was not possible to determine this.”

A Gulf Research and Development Company patent filed in 1945 (2494256) proposed a panoply of shaped charge configurations—as if to cover all possible uses. The document mentioned “numerous results of our experiments” that verified the penetrating power of the lined shaped charge and revealed the charges should be “provided with a suitable cover to pre vent any liquid entering the cavity (the liner).” The patent optimistically predicted that a slug would be “sufficiently small to pass through the hole in the casing and come to rest deep in the formation where it has negligible effect on the flow of fluids through the hole.”
The Great Crew Change: A Challenge for Oil Company Profitability
Authors: Coton Simon
Published: February 2015

Talent & Technology

We have all heard about the “great crew change,” the coming decade in which 50% of experienced and managerial personnel of international oil companies industrywide are expected to retire. While this will not all happen on a single day, it will create simultaneous gaps of unprecedented proportions in the staffs of many international and national oil companies.

As bleak a picture as such a summary suggests, the great crew change is only part of the personnel problem that will be common to oil companies over the next decade. The same period will be marked by many foreseeable challenges in virtually all producing areas of the world.

Take two examples: Iraq and Brazil. Iraq has already stated a goal of increasing oil production from the present 2.5 million b/d to 12 million b/d. Its infrastructure is outdated and war-torn. Needed power plants are yet to be built. Increased production will require three barrels of water for every barrel of oil produced, or a virtual river of 10 million BWPD flowing into the desert of northern Iraq. Material and logistics issues will be unprecedented. Iraqi projects alone could employ a large percent-age of the decade’s new engineers in all specialties.

Brazil has recently committed USD 200 billion to its five-year development plans. Their projections for these ambitious and well-funded goals show an estimated shortfall of 40,000 engineers stretching into the distant future.

But the competition for skilled and creative people does not stop: Some of the biggest oil and gas finds in the world are waiting development under the crushing Arctic ice of northern Siberia. Ultradeep subsea projects are getting deeper and farther from land by the year. National companies are also looking for the same kind of talent. Graduating engineers receive competitive offers from nuclear power and renewable projects proclaiming the careers of tomorrow. All of these factors are converging in the same decade.

Yet, even while facing such issues, international oil companies are questioning two of their traditional employment models: heavy reliance on expatriate workers abroad and heavy reliance on long-term career hires at home. Both practices will make workforces increasingly expensive in coming years.

The use of expatriate workers is already problematic both for host countries and foreign companies. Some countries now defensively ration expat positions by taking three to five months to process applications for work permits and visas. Additionally, a company wishing to employ an expatriate may have to satisfy protracted requirements to prove a negative, i.e., that there is no qualified national of that country available to do a given job.

On the home front, outside of core employee job tracks, the old model of long-term career hires will be incredibly expensive for international and fast-growing national companies. It will also be hard to implement in any worldwide operations where expat employees are increasingly restricted by host governments.
Technology Focus: Offshore Drilling and Completion (April 2011)
Authors: Santos Helio
Published: February 2015

Technology Focus

It has been a year since a tragic event in the Gulf of Mexico triggered the industry to rethink procedures and regulations on offshore drilling and completion around the world. Our evolution process has been marked by learning from mistakes, and that event should be no exception. Questions such as “What should we do differently to reduce risks?” and “Is there a safer way to perform this operation?” should be always asked, regardless of statistics that indicate we have been doing a good job. There is always room for improvement, and when dealing with lives—whether human, plant, or animal—there should be no limits.

The event last year also triggered more discussion and awareness about well integrity, including about how wells should be designed and constructed to face natural events. Hurricanes, earthquakes, and tsunamis are examples of natural events that we must take into account when designing and constructing a well. Most engineering structures that greatly affect the environment and human lives (e.g., buildings, dams, and airplanes) are designed considering parameters involving several times the expected life time of that structure, and with a generous safety margin when uncertainties exist. An offshore well falls into this category, regardless of how you analyze or look at it.

Understanding the challenges of the environment where we will construct our well, looking at available options and technologies that can reduce the risks, and learning from experiences are three basic steps that we should always take. The papers selected here try to cover these three aspects.

Offshore Drilling and Completion additional reading available at OnePetro: www.onepetro.org  

SPE 128302 • “Innovative Use of Plug-and-Abandonment Equipment for Enhanced Safety and Efficiency” by Delaney Olstad, SPE, Weatherford International, et al.

SPE 139493 • “Emergency Severance of Casing for Deepwater Operations: A Design, Build, and Test Program of Novel Technologies” by N. Richmond, Geoprober Drilling, et al.

SPE 132701 • “Equipment-Design Change Improves Cementing Operations From MODUs Operating in Rough-Sea Environment: Case Histories for Two North Sea Jobs” by T.H. Romstad, Statoil, et al.

SPE 137223 • “Casing-Wear Prediction and Management in Deepwater Wells” by Bill Calhoun, Chevron, et al.

SPE 136392 • “Independent Verification of Safety-Critical Elements” by Julien Marty, Bureau Veritas, et al.
Drilling From an FDPSO: A Two-Stack Approach
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 20491, ’Drilling From an FDPSO: A Two-Stack Approach,’ by Kenneth C. Hampshire, SPE, and J. Greg Noles, Murphy West Ltd., and Albert Kachich, Doris Inc., originally prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed.

One reason for the success of the Azurite floating drilling, production, storage, and offloading (FDPSO) vessel was the innovative approach in specifying the equipment to fulfill the drilling requirements. This resulted in the specification and deployment of many unique drilling components that combine to make up the drilling structure that extended from the seafloor to the surface.  

Introduction

The Azurite field is in 4,600-ft water depth in the Mer Profonde Sud Block offshore Republic of Congo, a part of the world that is without significant infrastructure to transport or store hydrocarbons. As a result, a requirement for developing the Azurite field was to find a way to combine drilling activity and oil storage economically. To do this, a drilling rig was installed on a floating production, storage, and offloading (FPSO) vessel—making it an FDPSO. This unique and innovative combination presented a variety of challenges. To address these challenges, one solution was to use two blowout-preventer (BOP) stacks while drilling, to ensure well control and reduce drilling risk.

Two-Stack Rationale

Controlling wellbore pressure is paramount to safety in drilling operations.  Conventional deepwater-drilling operations use a subsea stack of BOPs to achieve this. Many combinations of closure scenarios are available with a properly specified stack to reduce or remove internal pressure in the riser column above the stack. Well control requires frequent actuation of BOP functions.

Functionality and ease of maintenance would be enhanced greatly if the stack could be installed above the water line. Additionally, the size and weight of the surface stack would be significantly smaller than a subsea stack. The riser also would be simplified in that it would not need to carry hydraulic control lines down to the stack, and the riser would not need to have a choke or kill line.   

The idea of having a wellhead connected to a stack mounted above the water line with a high-pressure riser system was appealing, but having no protection at the seabed was not. The Azurite project team recognized that if the integrity of the riser was compromised for any reason and drilling or reservoir fluids escaped, the environmental consequences would be unacceptable. To address this concern, another stack, customized to safeguard against such an occurrence, was specified that would be a standalone module that would not require the rigorous functionality of the surface stack or require control lines running down to it from the surface. This package was called the subsea isolation device (SID). Fig. 1 shows the surface stack (left) and the SID.
Operational Risk Analysis of LNG Loading
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 20982, ’Operational Risk Analysis of LNG Loading,’ by B.H.K. Chin, P. Friis-Hansen, and T.G. Saetren, Det Norske Veritas, originally prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed.

The increased interest in risk analysis is the result of several operators wanting to understand properly their risks in the operational phase, and in this way, through proper preparedness, to avoid or mitigate incidents and major accidents and to improve resilience toward these unwanted events. The full-length paper presents the results of a detailed risk analysis of a liquefied natural-gas (LNG) export loading operation at a jetty. The analysis takes into account the interaction between the vessel crew and the land-based operators.

Introduction

The objective of operational risk management is to satisfy multiple requirements of multiple stakeholders to control losses from operations. One particular objective of an operational-risk-management system is that it should provide a strong ability to forecast conditions and give input to management before the development of dangerous conditions. A second objective is to approach risk in a holistic way in assessing risk from unwanted losses resulting from loss of life and property and the effects on the environment. This requires a thorough understanding of the technical-systems reliability, of the organizational performance, and of how the interaction between the two affects the total-systems performance. This implies that a practical requirement for risk management of unwanted losses during the operation phase is that the risk modeling should encompass the systemic interactions between technical and human organizations. The solution for systemic risk requires a holistic perspective in hazard identification, risk analysis, and risk mitigation. This may provide the operator with a useful set of risk-based indicators to guide the risk-management process.

Case-Study Description

The intent of the test case is to model the loading mode at an LNG jetty, identifying potential failure scenarios and determining the risk profile for the loading operation. The main objective is to determine the safety and on-time performance of the loading operation. The investigation examines the possibility of technical failures, the errors caused by individual human performance, the organizational influences on the operation, and the combined factors from interfacing two sets of technical and human organizational systems (i.e., the land-based jetty operation and the ship-based operation).

The process of transporting LNG has inherent risks associated with it. The LNG is handled in cryogenic conditions and if released, the vaporized gas can form a flammable or explosive mix with air at a flammable range of 5 to 15% concentration. The LNG carrier is on fixed charter, and the delivery performance is affected directly by the on-time performance of the LNG loading.
Drilling Performance Is a Function of Power at the Bit and Drilling Efficiency
Authors: Pessier Rolf , Wallace Steven , Oueslati Hatem
Published: February 2015

This article is a condensed version of paper IADC/SPE 151389, presented at the 2012 International Association of Drilling Contractors (IADC)/SPE Drilling Conference and Exhibition, held in San Diego, California, USA, 6-8 March 2012.

Understanding of basic drilling mechanics has been greatly enhanced by the use of today’s sophisticated data acquisition systems for both surface and downhole drilling data. These systems have also helped in identifying major dysfunctions—particularly, harmful downhole vibrations. Various methods are used to optimize drilling practices, including monitoring efficiency indicators, such as mechanical specific energy (MSE), as well as preventing harmful vibrations by adjusting drilling parameters real time.

However, focusing on the efficiency of components and the prevention of dysfunctions is only a partial solution. It is also necessary to focus on the magnitude of mechanical power delivered to the bit, as that defines the capacity of the system and directly affects efficiencies, operating practices, and performance.

The paper shows how the power at the bit and drilling efficiency vary as a function of drillstring and bottomhole assembly (BHA) configuration, bit selection, and drilling parameter. Field examples illustrate the magnitude of parasitic losses caused by well geometry and the downhole environment. In many cases it is striking to learn how little power is left for the drill bit, which in the end dictates the potential rate of penetration (ROP) and thus the cost per foot and economics of the drilling process.

Particular emphasis has been put on new and intuitive ways to visually display the power at the surface and downhole. These make it possible to quantify system limits and identify key dysfunctions in one simple graph that can be used in real time as well as in both pre- or post-well analysis. Better understanding of the entire drilling system and the functional relationship of its parts can be a strong driver for both short- and long-term improvements in system design, drilling practices, and bit selection, ultimately resulting in higher productivity and lower well construction cost.

Introduction

The oil and gas industry, unlike others, seldom focuses on power requirements for the rotating drilling system and their effect on performance and efficiency. This might be explained in part by the fact that for about 100 years roller cone bits have been the industry’s preferred drilling tool. Roller cone bits require relatively little torque due to their low aggressiveness, and, due to the limited load capacity of the bearings, they act as perfect torque limiters. The rotating power system therefore utilized only a small fraction of the total installed power of a rotary drill rig; lack of power was not considered a limiting factor.
Technology Focus: Offshore Drilling and Completion (April 2012)
Authors: Santos Helio
Published: February 2015

Technology Focus

In the 2 years since the Macondo incident, we have seen a lot of action toward new regulations, procedures, and norms to be implemented in an attempt to reduce the risks of those tragic events happening again. But the industry did not stop working; wells were drilled and completed, even in the Gulf of Mexico after the long period of inactivity. As expected, we saw a big focus on subsea-equipment testing and procedures and on needed equipment improvements. But we also saw many reports highlighting improved operational performance, confirming that the industry continues with significant activity.

We should work proactively with the public and regulators to bring a framework that will lead to a safer environment for everyone. And we should not be happy with just more paperwork that may not bring needed effective improvement. For obvious reasons, the first step has been focused on the equipment responsible for providing the last barrier of protection, the blowout preventer (BOP). One paper describes BOP upgrades, and another one discusses software-based deepwater-BOP testing. We all must recognize that there has not been a significant advance in terms of BOP testing in the last 30 years. We are still relying, most of the time, on the old paper disks to record tests and on forms filled in by hand to confirm the pressure and duration of the tests prepared on each component tested. We should do much better than that.

The third paper highlights the drilling campaign in a promising offshore area in Brazil. But do not forget the underground blowout that leaked oil into the ocean offshore Brazil a few months ago, reminding us that continuous improvement of all offshore operations must take place. The alternative is that we again will face setbacks like those in the Gulf of Mexico after the Macondo accident.

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

IPTC 14868 RasGas Rigless Drift Experience: New Technology and Evolving Best Practice—North Field, Qatar by Russell R. Van Nuis, RasGas Company, et al.

OTC 21925 Large-Bore Expandable Liner Hangers Significantly Improve Operational Cost in a Deepwater Gulf of Mexico Well by Michael Johnson, Halliburton, et al.

SPE 145876 Temporary Storm/Cyclone Well Suspension Using Inflatable-Packer Systems by Colin Ingram, SPE, TAM International
Managing an Export Manifold To Ensure Gas Deliverability
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 14425, ’Managing an Export Manifold To Ensure Gas Deliverability,’ by A. Priambudi, R.N. Baraba, N.W. Tranggono, and B. Aryanto, Vico Indonesia, prepared for the 2011 International Petroleum Technology Conference, Bangkok, Thailand, rescheduled to 7-9 February 2012. The paper has not been peer reviewed.

The Badak Export Manifold (BEM) is a complex system for gathering all gas delivered from upstream fields and for delivering hydrocarbons to a liquefied-natural-gas (LNG) plant and to commercial sites for the manufacturing of fertilizers and chemicals. The export manifold must maintain pressure, distribute gas flow, implement offtake logic during shutdown, and coordinate gas delivery. Much effort has been invested to improve export-manifold operations. Now, almost all of the BEM parameters can be monitored remotely to support better operation.

Introduction

Vico Indonesia produces approximately 405 MMscf/D of natural gas and 18,000 B/D of oil and condensate from four fields. The company also coordinates gas production, is pipeline custodian for all producers in East Kalimantan, and is responsible for delivering approximately 2.9 Bscf/D of natural gas gathered from many fields.

The company maintains, operates, and inspects more than 1000 km of pipelines, with a diameter range of 3 to 42 in. The East Kalimantan pipeline net-work is designed to transfer hydrocarbons from outlying processing facilities to the Bontang LNG facility and to other commercial sites in the Kaltim Industrial Estate (KIE).

The BEM (Fig. 1) is the beginning of two 36-in.- and two 42-in.-diameter pipelines that work in parallel toward Bontang. The BEM enables flexibility of gas delivery and maintains gas composition within acceptable specification. The pressure stability and gas specification are the most important aspects of the export-manifold operations. These operations become challenging with changing upstream-field conditions. When the pressure is decreased, the gas composition becomes richer and the gas sup-ply is reduced to a level that is less than the demand for gas and less than pipeline capacity. A quick decision and field action are required immediately to avoid LNG-plant shutdown and gas composition getting out of specification.

In addition to gas composition becoming richer, the pipelines cross hilly terrain that causes liquid holdup (LHU) in the pipelines. The LHU increases the backpressure on the upstream field, which, in turn, restricts natural-gas flow to the plant. Despite the supply flexibility, parallel operation of the pipelines makes the gas tend to flow to the line with less backpressure. The BEM attempts to sweep liquid in the parallel mode by segregating gas flow into a particular pipeline.
Sustainable Development With First CDM Project in Thailand
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146681, ’Sustainable Development With First CDM Project in Thailand E&P,’ by Chiratthakan Getwech and Lawan Pornsakulsakdi, PTT Exploration and Production plc, prepared for the 2011 SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, 20-22 September. The paper has not been peer reviewed.

A clean-development-mechanism (CDM) project takes aim at recovering and then using associated gas from the oil wells of Sao Thian-A field in Sukhothai Province, Thailand. Without a CDM project, this associated gas would continue to be flared. The CDM project involved the installation of a gas-treatment system to filter out hydrocarbon droplets from the associated gas before its internal use and sale to an external facility.

Introduction

The CDM project is one of three flexible mechanisms that allow Annex-I Parties* to implement projects that reduce emissions or increase removals by sinks in the territories of non-Annex-I Parties. The carbon credits generated by CDM projects are “certified emission reductions” (CERs) that can be claimed by the project investor. Thailand is classified as a non-Annex-I Party and is not obligated to meet any emission-reduction targets. Instead, Thailand is eligible to participate in the CDM project as a host country, and possibly attract environmentally friendly investment from governments and businesses of developed countries.

Sustainable development is a pattern of resource use aiming to meet human needs while preserving the environment so that such needs can be fulfilled now and in the future. There is interdependence among the three concepts of sustainability: environment, economics, and socio-culture. On the basis of this approach, sustainable development can occur only where the environment, the economy, and the social needs meet.

The Thailand Greenhouse Gas Management Organization (a public organization), or TGO, is an autonomous governmental organization with the specific purpose of reducing greenhouse-gas emission, reviewing CDM projects for approval, and performing its role as the Designated National CDM Authority in Thailand. CDM-project development in Thailand must function in accordance with TGO guidelines, as well as with its sustainable-development criteria.

*According to the United Nations Framework Convention on Climate Change, countries are divided into two main groups: those that are listed in the Annex I, known as Annex-I Parties, and those that are not, known as non-Annex-I Parties. The Annex-I Parties are industrialized countries that are obligated to respond to climate change by lowering their greenhouse-gas emissions to an average of approximately 5.2% below their 1990 levels over the 2008–2012 period.
Successful Discovery of Light Oil From an Unsuccessful Well Through Re-Entry
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 147247, ’Successful Discovery of Light Oil From an Unsuccessful Paleozoic Well Through Re-Entry - A Case Study of an HP/HT Well,’ by Haifa Al-Bader, SPE, Yousef Zaid Al-Salali, SPE, Vidya Sagar Duggirala, SPE, A. Manimaran, and S. Packirisamy, SPE, KOC, prepared for the SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November 2011. The paper has not been peer reviewed.

An exploratory well, the second deepest in Kuwait, had been drilled in the Mutriba field to 22,094 ft. Two formations, Kra-Almaru and Khuff, were perforated and tested. The tests revealed the presence of sparse gas, and it was decided to test and complete this well in the Jurassic formation through re-entry. The re-entry in this ultradeep well was full of challenges; however, by overcoming all the challenges, this well was successfully perforated, stimulated, and tested, which led to the first commercial discovery of oil and gas within the Jurassic reservoir in the Mutriba field.

Introduction

Two zones in Paleozoic and Triassic sections were perforated and tested separately to evaluate the presence of hydrocarbon between 18,500 and 21,500 ft. The well was completed in 2004. After undesirable results were obtained from the Triassic and Paleozoic formations, exploration teams studied the feasibility of testing Jurassic formations in this well through re-entry. Testing Jurassic formations in the Mutriba field from an existing well will be more economical than drilling a new well. A snubbing unit was deployed in 2008. In 2009, a suitable workover rig was deployed to test Jurassic formations in this previously drilled well. The location of the Mutriba field is shown in Fig. 1.

A snubbing unit had been used to isolate the open perforations of the Triassic zone with cement. Subsequently, a workover rig was deployed to test the prospect of a Jurassic reservoir. Testing the Jurassic reservoir behind two heavy-walled casings (7 in. 46.4 lbm/ft and 8⅝ in. 40 lbm/ft) combined with extreme sour and high-pressure/high-temperature (HP/HT) conditions warranted high health, safety, environment, and technical precautions.

Challenges for re-entry to this well included HP/HT conditions, a high surface pressure, and well-killing issues. Testing of the formation fluid revealed the presence of an unexpectedly high concentration of H2S (20%) and CO2 (2%), which presented challenges for coiled-tubing (CT) operations, stimulation, flowing the well, and fluid disposal.