bluuebunny/crossref_metadata_2025_split huggingface dataset:
Overview: Wellbore Integrity, Sand Management, and Frac Pack (September 2006)
Authors: Goodman Harvey E. 
Published: February 2015

Geomechanics tools are used to forecast, and then gauge, asset performance over time. Wellbore integrity, sand management, and frac-pack engineering design and execution practices are linked by characterizing the geological section in terms of rock mechanical properties. Often, seemingly unrelated events that can plague high-risk, high-cost developments can be understood best when the geological environment, the geology and geophysics, is described as an engineering material (i.e., the rock mechanical properties that include formation strength and stress). A consistent characterization of formation stress and strength with the geological structure, lithology, and seismic attributes used to recognize the prospect ensures that the explorationists' vision is linked to the well engineers' design.
Further, a consistent mechanical-property model for the field can be used to create a full-cycle asset-development plan from appraisal through abandonment, helping to reduce the risk of missed future opportunities resulting from well-systems-design constraints. Two examples come to mind.Reservoir-pressure depletion and subsidence can affect borehole stability to the extent that complex well designs are necessary to exploit the asset fully. Well placement depends on the subsiding reservoir section and on the reaction of the overlying geological section that must be drilled through to reach the reservoir.Sanding-potential risk usually increases with depletion. For compartmentalized reservoirs with varying depletion schedules, sand-risk mitigation often leads to one-size-fits-all completions that usually result in sand control. This method can limit re-entry options and decrease recovery. An accurate forecast of sanding tendencies for individual reservoirs, including the field production-management practices that affect sanding, can result in a more selective fit-for-purpose approach to completion design.
For land-based operations, the consequences of well complexity may be addressed more easily; the downside is a poor estimate of field recovery that can either reduce opportunities for outlying prospects or, in the worst case, cause the asset to seem uneconomic. For major-capital projects such as deepwater subsalt fields, the capital outlays are immense, with single wells costing U.S. $100 million. For these deepwater projects, it is required that fewer wells produce reliably for longer periods of time. Well engineers need to get it right the first time.
Wellbore Integrity, Sand Management, and Frac Pack additional reading available at the SPE eLibrary: www.spe.org
SPE 95715 "Prediction of Sand-Production Rate in Oil and Gas Reservoirs: Field Validation and Practical Use" by P.J. van den Hoek, SPE, Shell Intl. E&P B.V., et al.
SPE 98252 "Prediction of Sanding Using Oriented Perforations in a Deviated Well, and Validation in the Field" by I. Palmer, Higgs Technologies, et al.
SPE 95514 "Evolution of Frac-Pack Design, Modeling, and Execution in the Ceiba Field, Equatorial Guinea" by C.L. Cipolla, Pinnacle Technologies, 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.