bluuebunny/crossref_metadata_2025_split huggingface dataset:
Trials and Tribulations of a Long-Reach Well in Deepwater GOM
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 118705, "Trials and Tribulations of a Long-Reach Well in the Deepwater GOM," by Ron Day, Ramsey Fisher, SPE, and Louise Jacobsen Plutt, SPE, BP plc, and Nesny Pardo, SPE, Segun Jebutu, SPE, and Hans-Christian Freitag, Baker Hughes, prepared for the 2009 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 17-19 March. The paper has not been peer reviewed.
For deepwater offshore areas with irregular water-bottom topography, subsea infrastructure above the field often can be limited. Access to reservoir targets becomes constrained, particularly when drilling challenges exist above the reservoir, such as pressure ramps or layers with unstable lithologies. Long stepouts can be required. Strategies implemented to drill and access reservoirs successfully in a large faulted anticline in the deepwater Gulf of Mexico (GOM) are presented.

Introduction
Discovered in 1998, the subject field is in the Green Canyon protraction area of the GOM in a water depth of 6,800 ft. The main reservoir targets are stacked oil-bearing turbidite sands at a depth of approximately 9,800 ft below the mudline. As shown in Fig. 1, the field is a large faulted anticline 11 miles long by 4 miles wide. Development is complicated by shallow salt fingers that obscure seismic imaging of the north flank of the structure and create a complex water bottom across the middle of the field where water depth changes 2,200 ft across a 1-mile width. Because of this lack of clarity on the northern flank, the south flank of the field was developed first from a central drill center, designated as Drill Center One (DC1).

Drilling Challenges
Well U was the sixteenth penetration in the field. Like all development wells drilled from DC1, Well U had three strings of casing (36-in. surface casing set approximately 200 ft below mudline; 26-in. conductor casing set at approximately 1,200 ft below mudline; and 20-in. casing set at approximately 2,300 ft below mudline) set during the 2004 batch-set operation. However, Well U, would need to mitigate three main drilling challenges in its remaining 17×20-in., 14 3/4×16 1/2-in., and 12 1/4-in. hole sections. First, Well U would need to navigate through a 1,000-ft-thick laminated and thin-bedded sand, which had caused severe lateral vibrations to the drilling assembly in previous wells, making directional control difficult and occasionally leading to downhole-assembly failures. As a result, vibration management became crucial in drilling the 14 3/4×16 1/2-in. section in one trip. An additional complication in the 14 3/4×16 1/2-in. section was that it would reach total depth in a pressure ramp, which could contribute to borehole instability.
New Technology Applications for Improved Attic-Oil Recovery: Slim Smart Completions
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 12365, "New Technology Applications for Improved Attic-Oil Recovery: The World's First Slim Smart Completions," by Stig Lyngra, SPE, Abdulkareem M. Al-Sofi, SPE, Uthman F. Al-Otaibi, SPE, Mohammed J. Alshakhs, SPE, and Ahmad A. Al-Alawi, SPE, Saudi Aramco, prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3-5 December. The paper has not been peer reviewed.
Smart completions, passive inflow-control devices (ICDs), and maximum-reservoir-contact (MRC) wells are some recent technologies used to enhance recovery and extend the life of mature oil fields. In a Saudi Aramco field, one challenge was to maximize production from the inadequately swept attic-oil zone. Since 1995, new technology has improved oil recovery from this thin attic-oil zone. Technology deployments included recompletion with short-radius-horizontal (SRH) sidetracks, single-lateral re-entry sidetracks equipped with passive ICDs, and multilateral MRC wells equipped with intelligent completions. A slim smart completion (SSC) was run in a multilateral sidetrack enabling production optimization and control of individual laterals.

Introduction
This field in Saudi Arabia was discovered in the early 1940s. A pressure-support program was started after 8 years of primary depletion. During a 24-year period, the produced solution gas was reinjected as part of the reservoir-pressure-support program.
Gas injection was into the primary reservoir at the crest of a high-relief dome feature. A flank water-injection program was started in the mid-1950s, and it became the main field pressure-support mechanism.
After more than 60 years of production, approximately 57% of the oil initially in place in the primary reservoir has been produced. Still, the field water cut has remained less than 35%. The absence of vertical barriers, relatively long distance from injector to first-row producers, and managed production offtake have allowed gravity to play the primary role in the recovery process.
The main-reservoir permeability distribution (higher permeability toward the top, excluding the top 25 ft) allowed oil production from the top section while gravity drainage occurred in the lower, poorer reservoir section. As a result, water production has been very limited. The normal production practice during the first 34 years was to shut in any producing well with crude samples containing salt.

Attic-Oil Target Zone
The attic-oil section is approximately 25 ft thick. Saturation logs run in 2007 in wells very close to flank injectors indicated that this interval is at original oil saturations. Fig. 1 is a schematic showing the main layering of the attic-oil interval.
Shared Vision (June 2005)
Authors: Paccaloni Giovanni 
Published: February 2015

Sharing our time and our talents is essential to the long-term success of SPE. Volunteerism is one of SPE’s core values. As a volunteer-driven organization, we enlist the talents of our members to address both local needs and the broader interests of our global membership. Members work together to direct SPE activities, from planning the details of section meetings to developing a long-term plan that defines the future for the Society. Your participation ensures that SPE remains vibrant and relevant.
Volunteering also pays personal dividends for the time you invest. You can gain leader-ship experience or learn interpersonal skills that you may not be able to get in your job. You can meet and network with people who can help you solve problems and move ahead in your career. You can write technical papers and receive recognition for it. Many are motivated simply to be of service: to help others, to “give back” to the profession, and to make a difference in the world. Winston Churchill explained the value of volunteering this way: “You make a living by what you get, but you make a life by what you give.”
Despite the many rewards of volunteering, the demands of modern life make it more and more challenging for members to give their time. Some smaller sections have a tough time filling leadership positions—the same people continue to serve year after year. All too often, members say they are too busy to attend monthly meetings, much less take on a greater role as a volunteer. In fact, members everywhere cite similar reasons why they do not volunteer.
“I’m too busy.” People are busy—with the consolidation that has occurred in this industry over the last two decades, fewer people are handling more projects, and the pace of change is incredible. Our members are juggling the demands of family life as well. We must respond to the time constraints of our members by offering opportunities to serve in smaller bites of time. By doing a better job of planning section and committee tasks, we may be able to break a big job into smaller parts that several people share. Participating in online communities is another option, allowing you to sign on at a convenient time. We have begun conducting a considerable amount of SPE business through email, online communities and teleconferences to reduce the number of meetings for Board and committee members.
“I don’t have the support of my boss.” This is really a variation of the first reason—your manager believes you are too busy to take part in SPE activities. Part of my role is to make sure that industry executives are aware of the tremendous resources and value that SPE offers to professionals at all career levels. The key to getting management’s support is to demonstrate that your participation in SPE pro-vides an exceptional return on the investment of your time. The company benefits when you gain access to the latest technical knowledge and develop skills that will enhance your performance.
Overview: Coiled-Tubing Applications (June 2005)
Authors: Blount Curtis G. 
Published: February 2015

Having been involved in coiled-tubing (CT) technology for many more years than I care to admit, it is interesting to see how much has changed during the last quarter century. Improvements in CT manufacturing, materials, equipment design, and computerized monitoring, as well as a better understanding of CT mechanics, set the stage for rapid growth and acceptance of CT as a viable and versatile oilfield tool. I firmly believe that, following this initial technology surge, the advent of various knowledge-/experience-sharing conferences and joint-industry projects, focused solely on CT technology and needs, have accelerated this CT “revolution.”
The first technology-transfer gatherings I recall attending were the HydraRig-sponsored forums beginning in 1989 through the World Oil CT conferences beginning in 1993. There also were several other public and intercompany events offering forums for CT pundits during the 1990s. In 1996, recognizing the need to share ideas on a larger scale, the Intl. Coiled Tubing Assn. (ICoTA) introduced its roundtable conferences. ICoTA soon teamed with SPE to bring us what is now considered the premier CT technology-transfer forum. This year, estimated attendance at the 2005 SPE/ICoTA Coiled Tubing Conference and Exhibition was 880—up 100 from last year—not including an additional 57 Texas A&M U. students we “graying” technologists were happy to welcome.
As I was reviewing papers from recent SPE and SPE/ICoTA conferences for this month’s feature on CT technology, it became apparent to me just how much the focus of the CT conference papers has changed. It seems to me that most early-conference papers centered around CT mechanics—on why CT behaves the way it does and predicting when it will break—and around successful CT jobs for any number of applications.
Recent offerings focus more on mainstream issues and what I call CT exploitation.
- Reducing the cost and extending the market for CT drilling services.
- Improving operational and safety efficiency.
- Discussing successful CT programs.
- Delivering solutions to complex problems in areas lacking economically viable alternatives.
And, of course, there still are the ubiquitous novel and unique thought-provoking sub-jects the innovative CT community is known for.
Additional Coiled-Tubing Applications Technical Papers
Available at the SPE eLibrary: www.spe.org
SPE 92513 Underbalanced Coiled-Tubing Drilling: Update on a Successful Campaign
SPE 94058 Some New Developments Applicable to Coiled Tubulars
SPE 94159 World’s First Utilization of Coiled Tubing to Dissolve Hydrate(s) in an FPSO Riser: Case History
SPE 94102 An Effective Sweep-Cleaning of Large Deviated Wellbores Using Small Coiled-Tubing Systems
SPE 90558 Effect of Coiled-Tubing Curvature on Friction-Pressure Loss of Newtonian and Non-Newtonian Fluids—Experimental and Simulation Study
Technology Update: New Options, Improved Economics from Aerogel Insulation
Authors: JPT staff _ 
Published: February 2015

The challenges facing oil and gas operators seeking to develop new fields in hostile environments such as deep and ultradeep water are well documented and continue to increase. One important requirement for operators developing subsea fields is the ability to transport unprocessed hydrocarbons, which are frequently at high pressure and high temperature, over longer distances along the ocean floor. Without sufficient insulation, the hydrocarbons will cool and create hydrates/wax buildup that can eventually clog flowlines at significant cost to operators. Cabot Corp. has developed Nanogel aerogel, a nanoporous insulation product, to address associated economic and efficiency issues.
Sometimes called "frozen smoke," aerogels are light insulating solids. Nanogel is a hydrophobic aerogel produced as particles, each of which consists largely of air (≈95%) trapped in nanosized pores that severely inhibit heat transfer through the material.
A proprietary manufacturing method imparts mechanical benefits (NanoSprings) to the aerogel particles in addition to characteristics that make them useful for thermal insulation. The aerogel performs across a range of temperatures (from –200 to +250°C) making it applicable in systems ranging from liquefied natural gas (LNG) to high-pressure/high-temperature settings.
Four products have been developed for the oil and gas market—the Expansion Pack, Compression Pack, Particle Pack, and Thermal Wrap systems. The first two are pipe-in-pipe products and use half-shells made with Nanogel aerogel particles compressed and packed under vacuum. In field application, a series of half-shells is positioned in a pipe-in-pipe or other assembly and activated (vacuum is breached), resulting in form fitting of compressed particles into a desired shape, either filling the entire annular space (Expansion Pack) or, under higher compression, filling a predetermined portion of the annular space (Compression Pack).

Operating Economics
There are two ways in which improved economic impact is created during development of subsea fields—by allowing the use of smaller jacket pipes and by enabling the construction of longer tieback lines.
In the case of smaller jacket pipes, substituting Nanogel for other insulation forms (such as polyurethane [PU] foam/rock wool) allows operators to reduce the size of outer pipes without compromising system performance (U-value), resulting in:Material savings on pipe steel.The ability to fit more pipe sections on a barge or reel, thereby reducing the number of barge trips.The ability to use smaller lay barges that have lower day rates. For example, to achieve a target U-value of 0.7 W/m2·K with an 8-in. flowline, an outer pipe of approximately 14 in. would be required if the insulation were PU foam. With the Expansion Pack system, the size of the outer pipe could be reduced to approximately 11 in. (Table 1).
Flow-Assurance Lessons: The Mica Tieback
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 18384, "Flow-Assurance Lessons: The Mica Tieback," by A.L. Ballard, SPE, BP America Inc., prepared for the 2006 Offshore Technology Conference, Houston, 1-4 May.
Flow assurance plays a significant role in asset development. In the case of ultradeep water, the role is major. The Mica field uses the longest tieback in the Gulf of Mexico and has been in operation for more than 4 years. The Mica wells are tied back through two 29-mile flowlines (one for gas and one for oil) to a major facility (Pompano). A review of Mica, comparing original flow-assurance-design strategies with current operational strategies, revealed several learnings, particularly involving paraffin, corrosion, erosion, hydrates, and slugging.

Introduction
The Mica field is in 4,350 ft of water. First production was in 2001. It was decided early on that the Mica wells would be tied back to an existing platform. Three zones in the reservoir were deemed producible. The shallowest zone is a saturated-gas and -oil zone with a gas/oil ratio (GOR) of 1,330 scf/STB, oil gravity of 32°API, and a wax cloud point of 93 to 100°F. The middle zone is a near-critical fluid with a GOR greater than 3,000 scf/STB, oil gravity of 37°API, and a wax cloud point of 90 to 94°F. The deepest zone is a dry gas with a condensate yield of 5 STB/MMscf and condensate gravity of 44°API. Peak capacity from the reservoirs was expected to be 150 MMscf/D of gas and 15,000 STB/D of oil.
Pompano Tie-In. Pompano is a steel-jacket structure in 1,290 ft of water. Weight on the platform was not a major issue, so it was decided to construct a new process system for the Mica wells. Because a relatively small amount of oil was expected compared to gas, a separate gas-export pipeline was built for the gas while the oil was tied into the Pompano crude treater. New equipment built for the Mica wells includes a high-pressure (HP) separator, intermediate-pressure (IP) separator, low-pressure (LP) separator, turbine-driven centrifugal compressor, glycol-dehydration system, and turbine-driven generator. Fig. 1 shows the process system. The compressor suction is drawn from the IP separator at 450 psig and discharged to the gas-export line at 1,300 psig. The LP separator feeds into the Pompano compressors at 150 psig.

Design Challenges
Paraffin. With the cloud-point temperatures of the oil, paraffin issues were expected in the wells and in the insulated oil flowline. For a tieback of this length, it was not feasible to keep the fluids in the flow-line above the wax-appearance temperature during production. Pipe-in-pipe (PIP) insulation was designed for the oil flowline to spread out the deposited paraffin in the flowline as the oil cooled.
Deepwater, Subsalt Drilling From Nova Scotia, Canada - Case Study
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 98279, "Pore Pressure Prediction and Drilling Challenges: A Case Study of Deepwater, Subsalt Drilling From Nova Scotia, Canada," by C. Marland, SPE, and S. Nicholas, SPE, Halliburton; W. Cox, EnCana Corp.; C. Flannery, SPE, Murphy Oil Sdn. Bhd.; and B. Thistle, Nexen Inc., prepared for the 2006 IADC/SPE Drilling Conference, Miami, Florida, 21-23 February.
Offshore eastern Canada is an environment where deep water and the need to penetrate thick salt sheets increase the difficulties faced by drillers. The full-length paper details a deepwater, subsalt-drilling case history and examines the challenges of dealing with high pore pressures and variable fracture gradients. During drilling, conditions were encountered that required use of unconventional borehole sizes and on-the-fly drilling-design modification to deploy unplanned equipment rapidly.

Introduction
The Weymouth A-45 well is approximately 160 miles south by southeast from Halifax, Nova Scotia, Canada, in the deepwater area of the Scotian shelf. Seismic analysis identified the presence of a subsalt anomaly, the 150-m-thick Argo salt sequence. This sequence presented a potential drilling challenge and also a problem for prewell pore-pressure and fracture-gradient planning. Because of the challenges posed by the deepwater environment and the thick salt deposit, the well included a complex well design with concentric hole openers and an unconventional casing design. Despite potential hazards and complex well design, the drilling program allowed flexibility in decision processes and in well design to deal with problems encountered. Flexibility was particularly important when drilling through the salt body with a point-the-bit rotary-steerable system (RSS). Although the RSS was not planned for use below the salt, the success of the system in the shallower parts of the well led to its use below the salt and highlighted the flexibility of rotary-steerable technology.

Planning and Design
In August 2002, three seismic lines and six offset wells were used for initial analysis of the Weymouth Prospect. These data were used to generate overburden, pore-pressure, and fracture-pressure predictions. The six offset wells, including two deepwater wells, showed two different pore-pressure regimes unrelated to water depth.
The first pore-pressure regime was characterized by normal pore-pressure gradients to approximately 2900 m followed by a slow increase in pressure, averaging 22 kg/m3 equivalent circulating density (ECD) per 100 m through to total depth (TD). The second pore-pressure profile had a steeper pressure "ramp" from 3600 m with a rapid pore-pressure increase to 1800 kg/m3 and greater by well TD.
Overview: Reservoir Simulation and Visualization (June 2006)
Authors: Smart Tom 
Published: February 2015

In last year's overview of Reservoir Simulation and Visualization, the focus was on technology designed to handle the ever-increasing volumes of data that are readily available for use by reservoir engineers. This trend has continued and has resulted in some extremely innovative adaptations of technology toward reservoir management.
Large volumes of data produce large models, which in turn produce large amounts of simulation results. This large volume of simulation results is difficult to analyze by conventional means. Significant improvements have been made by extending the methods of analysis of reservoir-simulation results to use the senses of hearing and touch, in addition to sight, to better understand the mechanisms at work in large full-field models. Research has been done with methods of artificial intelligence to predict reservoir performance, such as the training of neural networks. It is essential that research continues in these innovative areas as the industry strives to maximize production to meet market demands.
On the traditional front, important research has continued in the area of grid coarsening and scaleup to reduce model sizes to more-manageable levels. Significant contributions have been made by both industry and academia, with improved methods for selecting layers for grouping and with new algorithms for including additional reservoir flow characteristics in the scaleup calculations. As computing power continues to increase, the inclusion of compositional fluids and geomechanical effects in full-field reservoir models is becoming more feasible.
Workflows continue to be invaluable to reservoir management. With the ambitious goal of simulating the geological model, significant work remains to enable seamless transition of geological models through to numerical simulation. As the industry continues to move closer to this goal, we will also move closer to the ultimate goal of managing risk and uncertainty better. Ongoing work to provide the tools to understand both the input and the output of these large models will largely determine the success of this endeavor.
Reservoir Simulation and Visualization additional reading available at the SPE eLibrary: www.spe.org
SPE 96410 "Reservoir Simulation and Reserves Classifications—Guidelines for Reviewing Model History Matches To Help Bridge the Gap Between Evaluators and Simulation Specialists," by D. Rietz, SPE, Ryder Scott Co., et al.
SPE 94319 "Improved Coarse-Grid Generation Using Vorticity," by H. Mahani, SPE, Imperial College London, et al.
SPE 97155 "How To Approximate Effects of Geomechanics in Conventional Reservoir Simulation," by A.T. Settari, SPE, U. of Calgary, et al.
SPE 96416 "Tuning an Equation of State—The Critical Importance of Correctly Grouping Composition Into Pseudocomponents," by A.A. Al-Meshari, SPE, Saudi Aramco, et al.