bluuebunny/crossref_metadata_2025 huggingface dataset:
Technology Focus: Subsea Technology (August 2009)
Authors: Salies Jacques B.
Published: February 2015

Technology Focus

As oil prices approach half of their value of last year, when they hit all-time highs above USD 147/bbl, here I am again to address the JPT audience. Against all odds and in spite of the difficult economic times, the 2009 Offshore Technology Conference (OTC) had extraordinary attendance, proving the breath and strength of our industry. The fact is that we are accustomed to ups and downs and to riding out tough times with innovation and willingness to embrace new solutions. Actually, this is the time to hold and value a strong engineering team that is motivated to face challenges, come up with solutions, and deliver oil and gas on time and on budget.

Those who attended the presentations at OTC had the privilege to witness the industry's accomplishments and promises. Among them was what might be one of the greatest developments offshore in ultradeep water in Brazil: the presalt formations. Last year, Petrobras started a pilot production project that allows testing technologies for the full development of these giant fields.

The industry's accomplishments and promises are represented by the papers selected for highlighting and for additional reading in this issue. They illustrate developments in the Gulf of Mexico, the North Sea, and Africa. As you read them, you will have the opportunity to know more about the design/qualification of the Tahiti field in the Gulf of Mexico, Chevron's first high-pressure subsea development, and improvements in efficiency for subsea operations in deepwater Angola implemented by ExxonMobil. In addition, you will know how StatoilHydro proved subsea compression to be a cost-effective alternative to platform compression in the North Sea. Other highlights include multiphase boosting installed in the BP King field, the Moho Bilondo subsea-production system, and the Agbami field development and its subsea-equipment systems.

Therefore, I would like to invite you to read this selection of papers, a testimony of our flexibility and willpower to endure and create in tough times. Enjoy it!

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

OTC 20146 • "BP King—Deep Multiphase Boosting Made Possible" by B.E. Davis, BP America, et al.

OTC 20280 • "Moho Bilondo: Subsea-Production-System Experience" by D. Carré, Total, et al.

OTC 19919 • "Agbami Field Development—Subsea-Equipment Systems, Trees, Manifolds, and Controls" by Thomas P. Kelly, SPE, FMC Technologies, et al.

OTC 20186 • "Subsea Processing and Boosting—Building Blocks for Petrobras Scenarios" by M.L.L. Euphemio, Petrobras, et al.
Real-Time Drilling-Process Optimization
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 119650, "Real-Time Optimization of the Drilling Process - Challenges in Industrialization," by E. Cayeux, SPE, E.W. Dvergsnes, SPE, and F. Iversen, SPE, International Research Institute of Stavanger, originally prepared for the 2009 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 17-19 March. The paper has not been peer reviewed.

A new drilling-control system for real-time optimization and automation has been developed in an ongoing research project, which now will enter an industrialization phase. The system, which is based on application of advanced real-time process models for calculation of both hydraulic and mechanical forces, requires an extensive set of input data. Results from the calculation modules are applied directly in the drilling-control system, affecting parameters such as pipe acceleration, velocity and deceleration, and the pump-startup profile.

Introduction

During the last decade, computer-controlled machinery have made it possible to control the drawworks, the topdrive, mud pumps, and the iron roughneck or pipe-handling equipment from a drilling workstation by use of joysticks and keypads. Recent developments enable control of the machinery within safe-guard boundaries through application of model simulations, accounting for the effects of fluid and pipe movements in the wellbore. These new extended systems have the potential to reduce the risk of damaging the well and the downhole equipment and, subsequently, to reduce nonproductive time. For such extended systems to function properly, a more precise description of the drillstring components is required to calculate pressure losses, mechanical loads, and heat transfer. Furthermore, complete descriptions of the wellbore architecture, formation prognosis, trajectory, and drilling-fluid properties are needed for configuration of the applied models. Most of this information is not available in standard rig systems, and no standard work process has been established to make this information available before actual operations. For such systems to achieve their full potential, the necessary information must be quality controlled and made available at the right time, because an error in this information could lead to potentially serious incidents.

In January 2008, a field test of a new system for automated control of the drilling process was performed on the Statfjord C platform in the North Sea. Because the system was developed through a research project, the focus up to now has been on robustness. The system now is entering the industrialization phase, with a stronger focus on system application, including the following.Sensor quality and reliability.Availability of wellbore description including information exchange between different systems.Work processes for updating well bore description and quality control of data.User friendliness.Personnel training.
Members Gain Professional Recognition Through Certification Program
Authors: Shillings Erica
Published: February 2015

Today's complex oil and gas industry and the increased workload caused by strains on the talent base leave little room for error in ensuring the technical competence of the workforce. And while the US, the UK, and some other countries have registration programs for engineers, many countries do not. In response, SPE has developed a certification program for engineers that allows them to demonstrate their technical knowledge.

Part of SPE's mission is to help members further their technical and professional competence and skills. The certification program defines required knowledge in different areas of engineering and offers members an opportunity to demonstrate their knowledge through examination.

SPE Petroleum Engineering Certification offers an international credential recognizing petroleum engineering expertise. The certification is obtained by applying for and passing the SPE certification exam. Prerequisites to taking the exam include an undergraduate engineering degree and 4 years engineering experience.

"The certification exam is targeted to areas of the world that do not have governmental licensing bodies to regulate the practice of engineering in that country," said Byron Haynes Jr., development planning team leader for Petroleum Development Oman, and chairperson of the SPE Engineering Professionalism Committee. "Engineers working in these parts of the world can take this exam to show that they possess engineering skills that can be verified through examination by an international body such as SPE.

"By taking the exam, people show their employers that they have engineering skills and experience that is recognized by an international standard—this metric has been used for internal promotions," said Haynes. "This exam is useful when applying for jobs to show prospective employers that they are qualified and that they have basic petroleum engineering skills that are recognized internationally."

Employer Support

Many employers support their employees taking the exam and offer incentives for doing so. "There are in many cases incentives such as the company paying for the exam, giving the employee time off to sit for the exam, and some companies are actually giving raises to engineers who sit and take the exam successfully," Haynes said. "This sends a message to the engineering community that these companies are supporting the establishment of an engineering certification program. These companies also use this exam as a training tool to verify engineering competence within the company and placement for other engineering assignments."
Comments (September 2004)
Authors: Donnelly John
Published: February 2015

Editor's column - No abstract available.
Pressure-Only Measurements Pose Challenge
Authors: JPT staff _
Published: February 2015

Technology Update - No abstract available.
Top Papers at ATCE Highlight Climate Change, Drilling, Water Management
Authors: Langley Diane
Published: February 2015

Technology Review - No abstract available.
Overview: Frac Pack (September 2004)
Authors: Norman David
Published: February 2015

Overview - No abstract available.
Frac-Pack Completions in a Deepwater Field With Inverted Sand/Shale Stress Contrasts
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 84259, "Design and Long-Term Production Performance of Frac-Pack Completions in a Gulf of Mexico Deepwater Turbidite Field Having Inverted Sand/Shale Stress Contrasts: Case History," by David A. Shumbera, SPE, Agip Petroleum, and Richard C. Ellis, SPE, and Darrell Loya, SPE, Mullen Energy, prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
Overview: Gas Production Technology (September 2004)
Authors: Wichert Edward
Published: February 2015

Overview - No abstract available.
Sand Management for High-Rate Gas Wells
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 86535, "Sand-Management Solutions for High- Rate Gas Wells, Sawan Field, Pakistan," by C.A. McPhee, SPE, Helix RDS Ltd., and C.K. Enzendorfer, SPE, OMV Pakistan, prepared for the 2004 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 18-20 February.
Quality Management and the Oil Service Company: Are They Compatible?
Authors: Stoute Ray A.
Published: February 2015

Quality Management Systems (QMSs) can be found in every industry regardless of the type of working environment. They may be formal or abstract in nature, a result of legislative requirements, or even custom-made to a company’s scope of operations. Whatever the format, the result should be the same—to ensure that the products or services provided to the customer consistently conform to specific, predetermined measures. The Intl. Organization for Standardization (ISO) is the world’s largest developer of standards, and its quality standards bridge all industries on a global scale. But when the term ISO is used in the same breath as the oil and gas industry, visions of environmental management, green engineering, waste management, and, of course, ISO 14001 are conjured up. Given the eco-thrust of new legislation appearing annually, it is in these companies’ best interests to adapt such concepts and ideologies sooner rather than later. Aiding this newfound respect for the environment is the increased focus on health, safety, and environment (HSE) policies. Today, all three components of HSE are entrenched in all aspects of the industry, with a marked improvement in attitudes and emphasis on safe and environmentally friendly work practices. How do quality and, more specifically, ISO 9001 fit into this picture?

The ISO 9000 and ISO 14000 families are among ISO’s most widely known standards, implemented by 634,000 organizations in 152 countries. ISO 9000 has become an Intl. reference for quality-management requirements in business-to-business dealings and is primarily concerned with quality management. Those issues include the customer’s quality requirements and satisfaction, applicable regulatory requirements, and how to achieve continual improvement performance in pursuit of these objectives. The ISO 14000 family is primarily concerned with environmental management, specifically what the organization does to minimize harmful effects to the environment caused by its activities and how to achieve continual improvement in environmental performance. The following case study highlights one oil service company’s successful attempt at ISO 90015 registration.
Safe Operating Window: Wellbore Stability Is More Than Just Fluid Density
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 94732, "Integrated Management of the Safe Operating Window: Wellbore Stability Is More Than Just Fluid Density," by T. Hemphill, SPE, Halliburton Baroid, prepared for the 2005 SPE Latin American and Caribbean Petroleum Engineering Conference, Rio de Janeiro, 20-23 June.

The drilling of challenging wells, especially those in deepwater, high-pressure/high-temperature, and extended-reach environments, often is characterized by a narrow safe-operations window between formation pore pressure and fracture gradient. Overstepping the window bounds can lead to unwanted incidents of lost well control and/or lost circulation. Maintenance of wellbore stability (WBS) while drilling is critical to the success of today’s challenging wells, yet applications of such modeling have largely centered only on predictions of surface drilling-fluid density requirements. An integrated approach demonstrated the use of incorporating drilling-fluid hydraulics and barite-sag potential in the wellbore-construction process to help avoid unwanted surprises that can lead to unstable wellbores while drilling in technically challenging environments.

Introduction

Recently, for an extended-reach-drilling (ERD) well in the North Sea, hole cleaning and hydraulics optimization were combined with wellbore-stability modeling to produce a more comprehensive analysis of a large-diameter interval to be drilled with water-based drilling fluid. In that study, a fully coupled wellbore-stability analysis was used to estimate the minimum drilling-fluid density to prevent shear collapse and the maximum density to prevent formation fracturing during initial stages of the drilling operation. Changes in key drilling parameters such as pump rate, drillstring rotation speed, and rate of penetration were made in a “what if” fashion to determine their relative effects on wellbore stability. Following the optimization process developed for drilling the well on paper, the large-diameter hole was drilled, and the casing was cemented successfully.

In the subsequent 12¼-in. tangent interval, drilled with low-toxicity mineral-oil-based mud (LTMOBM), the hole was drilled without problems, but hole instability occurred once drilling operations ceased. The hydraulics used in the actual drilling process near the bottom of the 12¼-in. interval was entered into the wellbore-stability model to re-evaluate the effects of drilling operations on wellbore stability. In this second study, a chemoporoelastic model accounting for chemical interaction between the drilling fluid and the formation, as well as full coupling between the change in pore pressure and effective stresses, was used.
Conductivity Endurance in the Unconsolidated Environment of the Gulf of Mexico
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 17116, "Conductivity Endurance in the Unconsolidated Environment of the Gulf of Mexico," by William Whitley, SPE, Unocal Corp., and Brad Clarkson, SPE, and William J. Edwards, SPE, Halliburton, prepared for the 2005 Offshore Technology Conference, Houston, 2-5 May. Copyright 2005 Offshore Technology Conference. Reproduced by permission.

The productive life of certain wells with frac-pack sand-control completions has shown a greater decline in performance than expected. In many cases, this abnormal decline, both initially and in the long term, can be attributed to loss of conductivity in the proppant pack. Because conductivity is the major design criterion for frac-pack completions, the conductivity must be optimized in the original completion and then maintained throughout the life of the well. When frac packing in weaker and unconsolidated environments, enhanced treatment materials and designs must be used to help ensure that frac-pack conductivity is optimized initially and maintained over the long term.

Introduction

Until recently, there was no way to prevent fines migration through the proppant pack to the wellbore. If the formation contains laminated, highly heterogeneous, unconsolidated, compactable rock, fines movement could impede the production of hydrocarbons from the well.

It is common to use a frac-pack procedure with a crosslinked gel system and a ramped proppant concentration to maintain sand control and improve conductivity from the formation to the wellbore. Maintenance of these packs, in certain reservoirs, has become an issue. In the past, some wells that were frac packed tended to lose the added conductivity in a very short time. One common theory is that the formation fines “plug” the proppant pack, thereby suppressing further fluid flow to the wellbore. Following this theory, if the production of formation fines flowing through the proppant could be decreased, the conductivity of the pack could be maintained better. Hence, conductivity maintenance is a main goal of the surface-modifying agent (SMA) being added to numerous frac packs in the Gulf of Mexico (GOM).
Q&A with Clarence P. Cazalot Jr., President and CEO, Marathon Oil Corp.
Authors: Cazalot Clarence P. , Donnelly John
Published: February 2015

As Chairperson of the 2006 SPE Annual Technical Conference and Exhibition, can you give us some highlights of this year's event?

One of the areas of focus that has become very important to the industry is unconventional hydrocarbons. That is becoming a dominant theme in the business today and is rejuvenating North America, whether it is Canadian oil sands, which have gone from being considered marginal just a couple of years ago to a very significant opportunity, or all the tight gas and fractured shales. Our company is moving more and more in that direction as well.

Another important topic that certainly will generate a lot of discussion at the conference concerns the issues about people and the technical skills critically needed by this industry, both now and in the long term. There also will be a panel on reserves classification, which has been a high-profile issue as well. And, of course, the focus on technology—what new technologies are needed and the advances that are being made today.

The conference's opening general session and panel sessions do focus on those critical issues: heavy oil's part in meeting future demand, reserves classification, and the role of young professionals. Do you think the challenges facing the industry now are greater than they have been in the past?

I believe they are. Some may disagree with me and say that the industry has always faced challenges and that this is not an easy business. But I do believe that today's challenges are potentially game-changers in terms of how and where we conduct our business. For me, it begins with the high commodity prices we are seeing. High prices certainly spur increased activity and provide economic incentives that are creating both current and future problems. The current problems you can see in the competition for people resources and for new opportunities and assets. They are driving up the very cost of doing business—from wages and salaries to seismic costs to drilling costs to land costs. For the long term, the big question is, "To what extent and how will demand for crude oil, natural gas, and refined products all be impacted by these high prices that have risen so dramatically in such a short period of time?" High prices also have attracted a lot of new competitors into the business, not just publicly traded companies but private equity, and caused the emergence of national oil companies much more rapidly than we otherwise would have seen.

In summary, I believe these challenges—access to resources, people, and rising costs—would have arisen anyway, but they have been exacerbated by the high-price environment. I think these are pretty fundamental challenges for the business that are bigger, and perhaps could have a greater impact, than the challenges that we have faced in the past.
Techbits: Assessing Managed-Pressure Drilling
Authors: JPT staff _
Published: February 2015

The SPE Applied Technology Workshop (ATW) "Managed-Pressure Drilling (MPD)" held during 11−14 June in Phuket, Thailand, drew 82 participants from 47 different organizations and 14 countries. The focus of the ATW was the use of MPD, precisely controlling the annular pressure in a closed system while drilling, to drill reservoirs that have been deemed economically undrillable by conventional means or to avoid drilling-related issues in others.

Wee Si Boon, Head of Wells Delivery (Malaysia), Shell Malaysia E&P, delivered the keynote address, titled "Developing Mud Cap Drilling and Completion Technology." His upbeat opening speech on the impact MPD has had on the Shell Malaysia operations emphasized its continued use to alleviate drilling problems in carbonate reservoirs often associated with severe lost circulation. These points were followed by comments on the wider application of MPD in the Asia Pacific region and its expanding use as a drilling enabler.

Ben Gedge, Brunei Country Manager and Shell E&P-Asia focal point for Weatherford, and Ian Davidson, Middle East Regional Manager, UBD Global Implementation Team, Shell E&P Intl. Ltd., gave the past, present, and future prospects for MPD and explained how this technology evolved out of underbalanced drilling (UBD) over the past 10 years, especially for the challenging drilling applications where full UBD is not appropriate.

The workshop reviewed the many applications for MPD, including, land, offshore, deepwater, high-pressure/high-temperature, and tight-gas air drilling. David Castillo, Director-Asia-Pacific, GeoMechanics, set the scene by reviewing and analyzing the many geological challenges that are encountered during the well-construction process and how these can be addressed with MPD techniques.

Particular attention was paid in the workshop to the cur-rent projects employing MPD techniques in Asia Pacific, particularly in carbonate reservoirs. Leo Maekiaho, Well Engineer-Operations, Shell Malaysia E&P, gave an overview of Shell Malaysia groundbreaking operations from jackups and semisubmersible rigs in the South China Sea. Andy Timms, Drilling Manager, Amerada Hess, reviewed a recent successful project in Thailand where high-pressure gas wells were successfully drilled with MPD technology, so much so that the number of development wells in the field was cut dramatically as a result of much-improved flow rates achieved with MPD technology (especially as a result of novel completion techniques).

Don Reitsma, Vice President-Engineering, At Balance, gave a description of a new dynamic-annular-pressure-control drilling technique that has only recently been commercialized.

Planning of MPD wells is one of the most critical parts of an operation. A group consisting of Oliver Coker, Principal Engineer, Conoco/Phillips; John Ramalho, UBD Regional Implementation Manager, Shell; Don Reitsma; Phil Frink, President, Blade Energy Partners; and Ben Gedge led the presentations and subsequent panel discussion.
Overview: Reservoir Performance and Monitoring (September 2006)
Authors: Clemens Torsten
Published: February 2015

Advances in technology enable improved reservoir characterization as well as improved measurement and allocation of relevant production and other data. The continuous advance in reservoir monitoring improves efforts in finding unrecovered hydrocarbons in fields with long production histories. However, as one of the featured papers shows, even in such fields, considerable production-forecasting uncertainties exist. Thanks to ever-increasing computing power, the uncertainties in production forecasting in these cases can be quantified and, thereby, managed. Various methods for assisted history matching have been used successfully to perform this task.

Time-lapse (4D) seismic has proved very successful in reducing uncertainties and finding remaining hydrocarbons. The technology is still developing at a fast pace. The application of 4D seismic has expanded from offshore to onshore heavy-oil developments. Because this technology is one of the few sources of surveillance information away from the well, new ideas are evolving of how to advance the methodology further. Another featured paper shows how geomechanical data were incorporated with the 4D seismic analysis, which might open another field for application of this method.

Geomechanical effects are important in various aspects of hydrocarbon recovery. They can be used in combination with 4D seismic, as mentioned above, and they are very important in water-injection and thermal-recovery processes. The third featured paper provides insight into coupling geomechanical effects and fluid flow.

Reservoir Performance and Monitoring additional reading available at the SPE eLibrary: www.spe.org

SPE 95419 "Production Monitoring Through Openhole Gravel-Pack Completions Using Permanently Installed Fiber-Optic Distributed-Temperature Systems in the BP-Operated Azeri Field in Azerbaijan" by G. Brown, SPE, Schlumberger, et al.

SPE 96897 "Mapping Fluid Flow in a Reservoir Using Tiltmeter-Based Surface-Deformation Measurements" by J. Du, SPE, Pinnacle Technologies Inc., et al.

Available at the OTC Library: www.otcnet.org

OTC 18222 "Constraining Reservoir Uncertainty With Frequent 4D-Seismic Data at Valhall Field" by H.S. Lane, SPE, BP plc, et al.
Sand Production in the Statfjord Field
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 97794, "The Relative Importance of Drawdown and Depletion in Sanding Wells: Predictive Models Compared With Data From the Statfjord Field MM," by M.H. Hettema, SPE, J.S. Andrews, SPE, and M. Blaasmo, SPE, Statoil ASA, and E. Papamichos, SPE, SINTEF Petroleum Research, prepared for the 2006 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 15–17 February.

Sand-production behavior at Statfjord field can be described as controlled by two sand-production regimes, one controlled by shear failure and the other controlled by rate. Study results show that sand production will limit well production rates for most formations and that sand control is needed to ensure high production rates during the late-life development of the field.

Introduction

The Statfjord field is a large oil field in the northern part of the Viking Graben and straddles the border between the Norwegian and U.K. sectors. The field has been in production since 1979, and both waterflood and gas injection have been used for secondary recovery. More than 65% of the original oil in place has been recovered. The Brent and Statfjord producing reservoirs consist of weak to intermediate-strength sandstone. The strategy used for many years is that produced sand is handled topside before on-site disposal. Producers are completed with a perforated liner and many have produced sand in a controllable manner from the time they came on stream. Because deep depressurization to produce solution gas is planned for late-life development, the study detailed in the full-length paper was performed to determine how the planned reservoir-pressure depletion will influence sand and field production.

Yearly sand production on each platform is estimated to be 50 to 100 tons. In the acceptable-sand-rate (ASR) test, the production rate is determined at which no more than 0.015 L of sand is produced in the sand trap during a 2-hour test. Because many producers are operated by an ASR criterion, field production is strongly related to sand production. If the planned reservoir depressurization leads to significantly more sand production, this would have unacceptable consequences for late-life production from the field.

Empirical Sand-Production Criterion

Sand production can be regarded as a three-step process:rock-matrix failure,erosion of the failed material, andtransport by fluid flow through the well. These steps are controlled by cohesion breakdown, drag forces, and well hydraulics, respectively.

Extensive production experience from Statfjord was used to determine how reservoir-pressure depletion will influence sand production. Critical drawdown pressure is defined as the drawdown pressure at which the ASR wells are tested and operated. To analyze field data, an empirical sand-production criterion relating the critical drawdown pressure, pcd, to reservoir pressure, pR, was used.
Gravel Packing Long Horizontal Wells With Low Fracture Gradients
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 96396, "The Dynamic Bottomhole Pressure Management: A Necessity to Gravel Packing Long Horizontal Wells With Low Fracture Gradients," by Z. Chen, SPE, and R.J. Novotny, SPE, BJ Services Co., prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October.

Unconsolidated formations are commonly found in offshore reservoirs where long and ultralong horizontal wells are required to produce heavy oil economically. Gravel packing is an efficient and cost-effective sand-control practice for these high-permeability, large-porosity, low-fracture-gradient formations. Successful placement of the gravel-pack completion requires that these low-fracture-gradient wells not be fractured during gravel placement. A dynamic-pressure-management scheme is critical to maintain bottomhole pressures (BHPs) in the required range.

Introduction

Horizontal-well openhole screen completions have been performed for years and offer many advantages. These advantages can be offset quickly by failure if the job is not carefully designed and executed. This is especially the case for wells with long and ultralong horizontal wellbore sections in unconsolidated formations with low fracture gradients. Although horizontal openhole gravel-pack completions have continued to gain acceptance as reliable completion techniques, they are still under development and often encounter new challenges. In some cases, there may not be any safe operational windows under conventional operation procedures.

Dynamic BHP Management

During gravel placement in horizontal wells, BHP must be monitored constantly to avoid fracturing the formation. Any excessive leakoff will cause a screenout and, thus, an incomplete sand-control completion. To ensure a successful packing job, an effective BHP-management scheme needs to consider both job-design time and actual job execution.

Gravel-Packing Model

The gravel-packing physical phenomenon in a horizontal well can be described as alpha-/beta-wave packing. Several flow patterns can be encountered in a given section, affecting the pressure-gradient/flow-rate relation. During alpha-/beta-wave packing, a stationary bed is created at the bottom of the flow path and a heterogeneous mixture of solid particles and carrier fluid flows through the upper part (Fig. 1). The stationary bed at the bottom of the flow path builds up and grows forward like a wave; it is from this that the expression "alpha wave" is derived.

The flow path or void above the alpha wave will be packed after the alpha wave packs forward to the bottom of the screen. In the alpha-/beta-wave model, it is assumed that the space above the alpha wave will be packed backward to the top of the screen. The packing process during this phase exhibits a pistonlike movement, packing all the space backward, and is named the beta wave (Fig. 2).
Petroleum Industry 2020: Positioning Our Industry for the Future
Authors: Al-Khalifa Abdul-Jaleel
Published: February 2015

As SPE President this year, I have had the privilege to visit many countries and meet thousands of our members, including senior leaders and professional engineers. I have felt the strength of our industry through its wise leadership, professional workforce, and cutting-edge technologies, which reinforced my belief that we will continue to supply adequate hydrocarbons to meet increasing human needs in the future.

Our future landscape will be different from the current one, however. Hydrocarbon resources will be a mixed portfolio, from conventional to very unconventional, from shallow to very deep, from light to extra-heavy, and so on. The human crew will be very international, one that is culturally open, flexible, nimble, and mobile. Our industry leaders will continue to pay more attention to human values and live the values of fairness and integrity while satisfying all stake holders, including asset owners (host government), share holders, customers, and the workforce. A role model for this leadership is Ali bin Abi Taleb, who once said, "Had I been offered the seven heavens, so I suppress an ant, sneak her little food, I would not do it."* Such leadership will ensure that performance appraisal, promotional opportunities, and career growth are pursued in a fair, transparent manner, which in turn will accelerate excellence and technology innovation throughout the industry.

As part of SPE's preparation for the future, the Industry Summit was held in London in June 2007. All attendees clearly supported an SPE role in enhancing industry collaboration and facilitating high-level involvement in industry-wide initiatives such as talent development and carbon capture and sequestration. The June 2007 SPE Board approval to form an Industry Advisory Council was a step forward to meet this objective. The council will further engage industry leadership and secure their support. This council will have senior-level representatives from 20 companies, including international majors, nationals, independents, and service companies. The council is expected to meet twice a year, initially for a 2-year period. We plan to hold the council kickoff meeting during the Annual Technical Conference and Exhibition in Anaheim in November 2007.

At the SPE leadership level, the Board has begun holding a strategic planning session along with each Board meeting. The first facilitated strategy session was held during the June Board meeting. The session included senior staff leaders along with the SPE Board members. These sessions will maintain a constant review of the Long Range Plan and will focus on major trends that affect SPE's mission. We aim to explore new means of fulfilling our mission in the most effective and expeditious manner. I am happy to report that this initiative is highly supported by the incoming 2008 SPE President, William Cobb. These initiatives and others will ensure that SPE will continue to be vibrant in the future.

*Ali Bin Abi Taleb, Nahj Al Balagah, http://www.al-islam.org/nahj/.
Long-Term Zonal Isolation for Onshore Gas Wells by Use of a Monobore Cemented Completion
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 107433, "New Approach To Ensure Long-Term Zonal Isolation for Land Gas Wells Using Monobore Cemented Completion," by Salim Taoutaou, SPE, and Ron Schreuder, Schlumberger, and Martin Bosma, SPE, Jules Schoenmakers, Rob Van der Vegt, and Dave Stewart, NAM B.V., prepared for the 2007 SPE Europec/ EAGE Annual Conference and Exhibition, London, 11–14 June.

A cemented completion provides an excellent opportunity for low-cost drilling techniques and simple well designs to reduce well-delivery costs without affecting safety or well integrity. In this concept, the completion is run straight into the open hole and cemented in place. There is no need to run a liner and perform a traditional clean-up. The cement effectively replaces the production packer. Achieving a good cement job is essential to a successful operation.

Introduction

The cemented-completion concept is a simple one whereby the reservoir openhole section is drilled to the required depth. Following electric logging (if required), the completion tubing is run into the open hole and cemented back inside the previous casing shoe or window. The Christmas tree then is installed and the well perforated in the normal manner.

Cemented completions already have been used in low-cost operating areas around the world. Well CA-28S2 drilled from the Cormorant Alpha platform in June 1999 marked the first cemented completion to be performed in the North Sea by Shell. Well CA-28S2 was selected as the ideal candidate for evaluating the method because of its short 6-in. openhole length (708 ft) and near-vertical inclination. Since then, openhole lengths have been increased progressively, culminating in Well CN-28S1 that was successfully completed with 6,500 ft of 8½-in. open hole at 67°.

In 2003, 79 cemented completions were installed by Shell globally, yielding considerable savings. In The Netherlands, after an initial trial with 5-in. completions in 2003, the land assets have adopted a 3½-in. cemented completion as a base case to the slimwell low-cost land drilling campaign that began in 2005 (Fig. 1). By the end of 2006, the 3½-in. cemented completion had been used successfully in eight gas wells.

Benefits

The advantage of a cemented over a conventional completion is that it saves 5 to 6 days of rig time during installation by eliminating such operations as running and cementing the liner, wellbore cleanup, and packer-setting procedures. In addition, the amount of liner and completion accessories required such as packers, liner hangers, polished-bore receptacles, and nipples is reduced. Savings depend on the completion and well design.
Identifying Condensate Banking With Multiphase Flowmeters - A Case Study
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 105362, "The Identification of Condensate Banking With Multiphase Flowmeters - A Case Study," by B.C. Theuveny, SPE, P.D. Maizeret, SPE, N.S. Hopman, SPE, and S. Perez, Schlumberger, prepared for the 2007 SPE Middle East Oil & Gas Show and Conference, Bahrain, 11–14 March.

Identifying condensate banking is a challenge. Large productivity losses can result if a condensate bank in the near-wellbore region is not detected early. One method that has been considered more theoretical than practical is detection of a leaner effluent stream at the wellhead during production. High-resolution measurement of subtle changes in the condensate/gas ratio (CGR) is essential for successful detection of condensate banking. The multiphase flowmeter can identify such a gradual change of the CGR.

Introduction

The main difficulty of testing gas wells with traditional test separators is determining accurate gas, condensate, and water flow-rate measurements. The short retention time in traditional test separators can lead to significant carryover of condensate into the gas line, resulting in underestimating the condensate rate and a potentially significant error in the gas rate. The level of error in the gas rate will depend on the measurement technology used. If a traditional orifice plate is used, the presence of condensate in the gas stream usually leads to an overestimate of the gas rate. The error in the gas measurement can be compounded with the accumulation of well liquids (i.e., water or condensate) in the tubing leads of the differential-pressure (DP) cell around an orifice plate, which can create large errors (usually identifiable in the raw data by a near-linear drift of the DP measurement). There also can be a significant amount of liquid trapped at the bottom of the pipe in front of the orifice plate, which can affect the flow-rate measurements adversely. Field identification of such a problem can be straightforward, but its remediation may be impossible during the course of the well-test operation.

Liquid carryover in the gas line is a large problem when testing gas wells with small separators. Short retention time, combined with very small liquid-droplet size, can lead to the entrainment of 50% of the liquid through the gas outlet of the body of the separator. Attempts to reduce the losses of condensate have yielded various levels of success. These efforts include centrifugal separation at the inlet of test separator and use of mist extractors. Although these methods improve separation, the remaining liquid carryover is not necessarily negligible.
Techbits: Capital Project Challenges Focus of Workshop
Authors: JPT staff _
Published: February 2015

Techbits

Project managers and key decision makers converged on Abu Dhabi, UAE from 23 to 26 March 2008 for a workshop titled "Challenges in Delivering Capital Projects." In five sessions spanning three days, attendees exchanged ideas and experiences in major project execution challenges and learned about the key factors in identifying project challenges, predicting portfolio profitability, and understanding the various uncertainties impacting today's oil and gas industry.

Aqeel Madhi, Chief Executive Officer of NPCC, gave the welcoming address, in which he highlighted the challenges facing oil and gas projects such as market conditions, contracting strategies for owners, and unique challenges and risks for both contractors and owners. Madhi proposed actions and efforts that owners and contractors can undertake to mutually benefit and move a project toward successful execution. Many of these were discussed in detail in the subsequent sessions.

Session 1: Capital Project Execution Challenges

Session Chairpersons Mohammed Abdul Majeed and Shaker Faras of Kuwait Oil Company (KOC) helmed the first session, which was designed to take stock of the performance deterioration of recently executed projects and discuss the advantages of new methodologies being applied to reduce this trend. Core issues of capital projects were also addressed, such as budgeting, cost estimation, contract strategies and most importantly, achieving on-time completion.

Al Attar of KOC gave a presentation highlighting the evolution of strategies to cope with high energy demand. He opened with a brief discussion on KOC achievements and aspirations and discussed KOC's experience in developing strategies and tools to create dynamic organizations that evolve with changes in the global environment. He also discussed best practices in prioritizing production portfolios, the relation between types of reservoirs developed and market conditions, the framework of the Health of Strategy (HoS) processes, and inputs and outputs to HoS.

A breakout group discussion followed, which focused on what an organization can do to stay dynamic, including using creative thinking to change management relationships with project teams, giving workers incentives to change or try new things, and creating value propositions to support change.

The second presentation highlighted the relationship between human resources (HR) management and performance risk. As new employees enter a project, new challenges enter as well, including a potential reduction in performance and possible project cost increases. To reduce these risks, a successful company should have dynamic hiring and employee management protocols, leaders with vision who value their employees, and a clear management vision that does not rely on following the activities of its competition.
Digital Technologies for the Next Trillion Barrels
Authors: Moon Ted
Published: February 2015

Technology will continue to play a vital role in the E&P sector's quest to satisfy global energy demand, and digital technologies will no doubt make the most significant impact. The term "digital oilfield" has emerged in the last decade to describe using information technology (IT) to monitor and manage all operational activities in real time or near real time, regardless of geographical location.

Subject matter experts representing operators, oilfield services providers, and IT developers recently described how the digital oilfield will evolve in coming decades to help find and produce the next trillion barrels of hydrocarbons. According to Don Paul, President and Managing Directsor of Energy and Technology Strategies, the industry has made a great deal of progress in a relatively short period of time.

"A few years ago, people were talking about the digital oilfield in a conceptual way, such as how to put more sensors in the field to gather more data and how to integrate subsurface and operating measurement. Now the industry is moving fully into implementation, and companies are redesigning their workflows and organizations around the flow of digital information. Ten years from now the situation will look radically different, because the technologies powering our processes will be much more powerful, providing more data and the opportunity for true real-time optimization of production operations."

Before postulating on the changes in 10 years and beyond, Paul put this timeframe in the proper context. "Projections for oil and gas demand and supply growth are often estimated in timeframes of decades, which is an eternity from a digital technology viewpoint. If you believe in the Moore's law effect [the 40-year old concept stating that capabilities of digital electronic devices improve at roughly exponential rates, doubling every 2 years], then in 30 years you are talking about a growth in computing power of 2 raised to the power of 15."

Furthermore, technology development and implementation follows cycles, and in Paul's experience as the former Vice President of Technology with Chevron, a new cycle starts when there is about a factor-of-10 change in the capability of the underlying technology. "That factor-of-10 jump in computing capacity is sufficiently large to enable shifts in the technical base and the work processes around the technology," Paul says. "In 30 years we are looking at five factor-of-10 changes if Moore's law holds. To put this into perspective, this is greater than all the change capacity we have had since the advent of digital computing."

This vast transformation in computing power will significantly impact and transform the energy system along several fronts.