We have completed a conceptual design study of the field-reversed mirror reactor. For this reactor a reference case conceptual design was developed in some detail. The parameters of the design result partly from somewhat arbitrary physics assumptions and partly from optimization procedures. Two of the assumptions-that only 10% of the alphaparticle energy is deposited in the plasma and that particle confinement scales with the ionion collison time-may prove to be overly conservative. A number of possible start-up scenarios for the field-reversed plasmas were considered, but the choice of a specific start-up method for the conceptual design was deferred, pending experimental demonstration of one or more of the schemes in a mirror machine. Basic to our plasma model is the assumption that, once created, the plas

A case history from Offshore Israel is presented that describes the successful delivery of five (5) ultra high-rate gas wells (+250 MMscf/D) completed in a significant (10 TCF) gas field with 7 in. production tubing and an Open-Hole Gravel Pack (OHGP). Maximizing gas off-take rates from a gas reservoir with high flow capacity (kh) requires large internal diameter (ID) tubing coupled with efficient sand face completions. When sand control is required, the OHGP offers the most efficient as well as the most reliable, long-term track record of performance. A global study of ultra high-rate gas wells was made to select and finalize the design concept after which the commensurate engineering rigor was applied. This paper will highlight key accomplishments within various phases of a completion delivery process for critical wells. The completions were installed with minimal operational issues (Average NPT 4%). Production commenced on March 31, 2013 without incident thus far. Each well is designed for production rates in excees of 250 MMscf/D. SPE 166368 Project Statement of RequirementsGeneral. The Tamar field is the only local source of natural gas to Israel, a country with a total population of ~7.9 million people. With five (5) wells producing from the Tamar field, each well is required to provide gas to ~1.6 million people, roughly the population of the U.S. state of Hawaii. With so many people depending on each Tamar well, delivering wells with the highest reliability and longevity became the key goal of the basis of design and all subsequent decision making. Phase I of the Tamar project was designed for a maximum flow rate through the subsea system and the platform of 1200 MMscf/D. To meet this flow rate, five (5) wells capable of producing 250 MMscf/D each were required with the completions to be finished by year end 2012. To ensure the wells were cleaned up and had the necessary productivity to meet Phase I deliverables, it was required to unload and produce the wells up to 120 MMscf/D to the drilling rig immediately following the completion.Key Project Deliverables. Drill and complete five (5) wells each capable of safely and reliably producing gas at rates of up to +250 MMscf/D for 25 years. Completion Guiding PrinciplesA set of completion key performance indicators (Table 1) and guiding principles ( Table 2) were developed to guide the decision making process for the completion design. These principles were largely based on learnings from other successful high-rate gas well developments and the key project deliverables defined above.

A case study is presented involving Noble Energy Mississippi Canyon Deepwater (DW) Gulf of Mexico frac packs performed over the last 5-years. This paper describes the role that proppant tracers and gravel pack (GP) logs played in improving operations, ensuring a complete annular pack, evaluating frac pack (FP) efficiency, and providing data for decision making as well as identification of best practices. Eight (8) DW completions involving thirteen (13) FP treatments and an associated seventeen (17) GP logs have been performed over the last 5-years in water depths ranging from 4,000 to 7,000-ft and reservoir intervals between 15,000 and 27,000-ft with pore pressures between 10.5 and 14.1-ppg. Proppant tracers and GP logs were utilized to confirm GP integrity, assist in reservoir performance evaluation, help guide start-up procedures, and serve as reference information for creating best practices in the operator's FP designs. The proppant tracers were injected into the proppant slurries from the start of proppant addition until screen-out. In most cases, washpipe-deployed spectral gamma ray and gamma density logging tools were then pulled across the completion interval as the washpipe was pulled out of the hole to record the frac coverage and annular pack quality. In cases in which a re-log or re-frac was performed, the logging tools were deployed via slickline. Seventeen (17) logs were evaluated and categorized in this paper to demonstrate the benefits gained. Some cases are limited to observations only (within the limits of the gamma ray tools, without final understanding of the why or how). However, on two (2) occasions, the logs identified that the gravel pack tools had failed and/or that there was no annular pack achieved. Both zones were re-stimulated and re-logged which confirmed annular GP integrity. Both wells are currently producing without compromise to productivity, flux limit or any detrimental sand control issues. If the logs had not been run and evaluated, both wells likely would have failed, losing either the lower or both the lower and upper intervals. On two (2) other occasions, voids were identified in the gravel packed intervals. In the first instance, the log was re-run after the upper completion (10-days later), and the pack had settled, eliminating the void. This information saved the operator from an unnecessary wellbore intervention ($10 MM+), allowing the ramp of the well to maximum design rate without otherwise imposed constraints. It also provided the confidence to move ahead on the subsequent instance where a void was identified. The results and the learnings presented in this paper can assist others in the industry when similar challenges are faced. Deepwater completions must be productive and reliable. Proppant tracing and gravel pack logging can assist the operator in real-time operational decision making, production start-up procedures, and future completion design modifications, to ensure that maximum benefit is realized from the sand control treatment. This is another useful tool that every completion program needs in order to ensure success and avoid preventable failures.

A Gulf of Mexico case history is presented that describes the successful delivery of two (2) deep (27,000-ft) high pressure (>17,500-psi) high rate design (25,000 BOPD) oil wells in an ultra-deep water (+6000-ft) environment. Well conditions, coupled with challenging production requirements (depletion of 10,000-psi), provided a very arduous design challenge. One well was completed as a single frac pack at 27,000-ft MD. The second well required a stacked frac pack at 25,000 ft-MD and intelligent flow controls. Twenty-seven (27) firsts, to the industry and / or Noble, were required to deliver the final completion designs. These firsts ranged, to name a few, from a new tieback casing material, a paradigm change in the Temporary Abandonment (TA) procedure (which yielded a cost savings of $15 million per well), a new perforating charge, qualification of a new material for the Gravel Pack (GP) packer, weighted frac fluids, changes in the upper completion designs, Vacuum Insulated Tubing (VIT) welding qualification and re-design of a control line Y-block. Any one item or any single technology gap, is seldom insurmountable. However, it is the layers and the multitude of challenges in these type of environments, where every component and their interdependencies are stretched to the edge of the design envelope that pushes the completion team and suppliers to their limit. All of these together make the goal of flawless execution very challenging. This paper will provide an overview from design thru operations, and highlight some of the engineering challenges and lessons learned. A field proven completion delivery process combined with a team of experienced people and rigorous procedures successfully designed and delivered two (2) complex completions that were on the edge of deep-water completion technology. Based on the Rushmore Review database, both wells (1 single GP and 1 single selective GP) were the fastest completions (when analyzed on a well depth basis) since Macondo. Both wells were completed in 2015, and are currently waiting on final hook-up and commissioning. First oil is forecast for July 2016. Industry will continue to explore ultra-deep water and discover deeper and higher pressure reservoirs that push the completion technology envelope. It is imperative that engineers be able to confidently design and deliver completions for this extreme environment that will achieve the productivity and reliability required by the project economics. The aim of this case history is to provide the engineer, faced with similar challenges, with information that may prove beneficial in the approach, method, design and delivery of these type of complex, critical completions.

A case history from Offshore Israel is presented that describes the successful delivery of five (5) ultra-high rate gas wells (ϩ250 MMscf/D) completed in a significant (10 TCF) gas field with 7 in. production tubing and an Open-Hole Gravel Pack (OHGP). Maximizing gas off-take rates from a gas reservoir with high flow capacity (kh) requires large internal diameter (ID) tubing coupled with efficient sand face completions. When sand control is required, the OHGP offers the most efficient as well as the most reliable, long-term track record of performance. A global study of ultra-high rate gas wells was made to select and finalize the design concept after which the commensurate engineering rigor was applied. This paper will highlight the design, qualification, Quality Assurance / Quality Control (QA/QC) and operational performance of the completion fluids inclusive of the Reservoir Drill-in Fluid (RDIF) and the breaker. Completion fluids are critical to the success and production efficiency of an OHGP. The completions were installed with minimal operational issues (Average NPT Ϸ4%). Production commenced on March 31, 2013. All wells have performed to expectations with maximum well rates up 340 MMscf/D.