Noble (United States)

Regardless of the direction of development and changes in the energy sector, the Worlds economies will rely primarily on natural resources for at least the next 20 years and very likely beyond. Actually, the resources of hydrocarbons in place in comparison with consumption are almost inexhaustible, so the question is only in the cost of production. For this reason, the exploration for new commercial fields that can withstand price volatility over a long period of time will play a critical role. At the same time, one of the most promising areas is the exploration of the new super-deep (more than 6000 m.) oil and gas accumulations.
 The information presently accumulated by geologists allows a high probability of finding profitable reserves, including liquid hydrocarbons, in ultra-deep horizons that were previously considered non-perspective due to extremely adverse thermobaric conditions. Commercial oil and gas potential of various sedimentary formations in such conditions is established for more than 70 basins around the world. There are large and giant gas, gas condensate, oil and mixed phase-heterogeneous fields, of which more than 1,200 are already being developed. Over the past 10 years, the most significant success has been achieved in the Gulf of Mexico (USA, Mexico), the Tarim and Sichuan basins (China), the South Caspian basin (Azerbaijan, Russia and Kazakhstan), the Santos basin (Brazil), and the Arab basin (Middle East). More than 120 hydrocarbon fields were discovered and most of them have yet to prove their commerciality.
 Pre Caspian basin is one of the most prospective regions, where deep horizons are poorly explored. For a better understanding of its potential, statistics on 106 clastic and 36 carbonate fields was collected, and 22 Paleozoic basins were considered as analogs. Data from 15084 documents with varying degrees of significance was taken into consideration; and elements of Artificial Intelligence (AI) processing were applied. Their simultaneous interactive analysis allowed to identify several possible analogues for Pre-Caspian basin and to justify the exceptionally high perspectives of its ultra-deep horizons.
 Many analysts identify three strategic directions for EP activities. The first type includes new perspective horizons in new basins, the second direction is associated with new reservoirs in already known oil and gas basins, and the last, third type includes prospects in already known productive sections of previously explored basins. Pre Caspian basin to some extent, corresponds to all three groups, but mainly to the second and third. Main interest is associated with well-studied Devonian reservoirs on the periphery, rapidly dropping towards the center of the basin, or with almost unexplored to date lower Paleozoic horizons. This article opens a series of publications devoted to the topic of discovery and development of ultra-deep hydrocarbons.

Abstract Tamar is a high permeability clastic gas reservoir that behaves like a well-connected tank, in many respects. At the same time, it has a significant level of complexity. The reservoir is comprised of three sand intervals, which are separated vertically by shales and broken into a number of fault blocks. While the degree of aquifer support has been an uncertainty, it is believed that the field demonstrates components of both bottom water and edge water drive. All Tamar wells were equipped with permanent downhole pressure and temperature gauges, and the surveillance of these pressure and rate data over the five-year production history has provided an unusually comprehensive data set. This dataset supports the high-resolution evaluation of well interferences and multi-well analysis. Investigation of the data on a well-by-well basis using conventional Pressure Transient Analysis techniques provided valuable insights, albeit primarily at the fault block scale. However, extending these investigations to the field scale generated some conflicting interpretations which could not be resolved by traditional PTA and standard reservoir engineering techniques.

Oil and natural gas producers continuously strive to control costs, and that goal becomes even more important when market conditions are challenging. To maximize the return on their capital investment and continue to extract reserves on legacy fields, many owners and operators are looking for ways to extend the service lives of aging assets. The Neptune Spar was the first production spar platform in the world, when it was installed in 1996. Currently owned and operated by Noble Energy, the unit continues producing at Viosca Knoll 826 in the Gulf of Mexico. As the platform ages, there is an interest in extending its service life to allow continued operation in the field. As requested by Noble Energy, ABS Group initiated a life extension assessment project. This paper describes the process of the Neptune Spar life extension assessments and challenges encountered during the process. One of the critical aspects of the life extension process is regulatory approval. Since the life extension for floating production platforms is a relatively new trend in the offshore industry, the regulatory compliance process is still under development, and this project is providing a significant contribution to the development of guidance and criteria. The purpose of a life extension assessment is to understand the history of the facility and its current physical condition to determine its structural integrity and outline what is needed for the unit to be maintained for safe and responsible extended service. The life extension project began with a roadmap for life extension assessments that included conducting baseline inspections, reviewing historic inspection and repairs records, undergoing gap analyses that compared the spar's current condition with the original design premise and calculations, and performing additional engineering analyses. As part of the regulatory approval process, the U.S. Bureau of Safety and Environmental Enforcement (BSEE) and the U.S. Coast Guard (USCG) require that a Certified Verification Agent (CVA) verify the entire process of life extension and submit reports that document findings and recommendations. ABS served as the CVA. During the life extension assessment process, ABS Group and Noble Energy consistently coordinated with ABS, BSEE and USCG. Based on the life extension assessments, ABS has granted class certificate for the life extension of this platform. The process of the spar's life extension assessment provides industry with a better understanding of the technical requirements for life extension of other floating production assets, which will have a long-term impact on future asset integrity management for these types of facilities in deep water.

Abstract 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.

Abstract Understanding wellbore position and the associated uncertainty is fundamental to all drilling operations and reservoir management. Without consistency in predicting to known uncertainties, activities involving positional uncertainty, such as risk mitigations for collision avoidance, cannot be performed reliably with known confidence. For the first time, industry has a common controlled set of uncertainty models thus allowing for transparency in error estimation. Reservoir targeting and subsurface hazard avoidance can be compromised resulting in unrealized stranded reserves and/or intersection of faulted, undesirable formation. Overly optimistic estimations can result in wellbore collisions where the risk of collision is assumed to be very low or can result in a missed well intersection during relief well first ranging point operation. Conversely, overly conservative estimations can result in excessive targeting constraints or directional control requirements. An analysis of industry survey of error codes being utilized across companies was performed, both vast inconsistencies and significant gaps were realized. A case for action was determined and a collaborative work group was formed under the Operator Wellbore Survey Group (OWSG). OWSG is a subcommittee of the SPE Wellbore Positioning Technical Section (SPE-WPTS). The SPE-WPTS originated as the Industry Steering Committee on Wellbore Surveying Accuracy (ISCWSA), which affiliated to the SPE and became a Technical Section. It was determined that many of the error codes being utilized in industry were based on survey tool error models established in SPE 67616 and SPE 90408, but there were uncontrolled changes, miss matched versions, and alterations in error assumptions (that were not vetted) being unknowingly utilized. Inspection revealed that the error models, although loosely based on ISCWSA, were varied across both service and operator companies and in some cases were varied internal to individual companies. The collaborative work group was established to develop a Standard Survey Tool Error Model Set based on the SPE 67616 and SPE 90408 publications, the current work of the ISCWSA error model subcommittee and with contributions from industry's leading subject matter experts. The result of the work is a series of 5 sets of OWSG Survey Tool Error Models. The sets have a Model Selection guide with a Standardized naming structure. The Standard Survey Tool Error Model Set has been released into the public domain to improve Survey Management Quality and has been adopted by numerous companies (both services and operators). The OWSG error model set facilitates easy implementation in all common directional well planning software platforms; hence reducing risk of incorrect models leading to poor understanding of wellbore position and improving consistency of error estimation. The Standard Survey Model set has been compiled with contributions from industry's leading subject matter experts. The most recent second revision (Rev2) of sets A and B of the series were publicly released during the month of June of 2015.

Abstract Shale reservoirs have low permeability, high fluid efficiency, and low fluid leak-off making these types of reservoirs ideal for hydraulic fracturing. One of the biggest challenges in analyzing unconventional shale reservoirs is that their flow regimes stay in transient flow for a very long period of time. This aspect of unconventional shale reservoirs makes it very challenging to estimate recoverable resources along with reservoir properties such as fracture half length, permeability, drainage area, and fracture conductivity. Conventional decline curve analysis assumes constant flowing bottom-hole pressure, drainage area, permeability, skin, and existence of boundary dominated flow. Most of these assumptions are no longer valid in unconventional reservoirs. Therefore, it is crucial that not only rate, but also pressure and other reservoir parameters are taken into account to properly evaluate unconventional wells and determine the true flow capacity of their reservoir in linear transient flow. This study uses rate transient analysis (RTA) which plots pseudo normalized pressure versus material balance square root of time to estimate the productivity of Marcellus Shale wells. Our dataset is limited to a restricted area located in Greene and Washington Counties, Pennsylvania, with similar reservoir properties such as porosity, water saturation, pressure, and temperature. With limited variation in reservoir properties, the slope of the superposition plot used to calculate AK becomes a good metric for well productivity. The y-intercept from the same plot indicates the completions effectiveness of the well. The slope of the line for a well with zero completions damage intersects the origin. Any completions damage (skin damage) caused by poor completions designs or unfavorable reservoir properties will have a higher y-intercept in relation to the origin in the superposition plot. After performing this analysis on operated wells in the study area located in Washington and Greene Counties, the wells with the most successful completions methods were identified. This knowledge can then be applied for future wells in the same area for optimum production enhancements.

The American Association of Petroleum Geologists (AAPG) Publication Pipeline Committee's (PPC) primary goal is to be a "pipeline" of donated geoscience publications to requesting and qualified overseas universities. Shipments are made with the assistance of AAPG members, student chapters, affiliated societies and companies with overseas operations. To date the committee has shipped to universities in more than 15 countries, reaching an untold number of geoscience students and faculty. Founded in 2000 by AAPG members and former Amoco colleagues Martin Cassidy and Rick Wall, the PPC currently has a total of ten members based in Houston (the abovementioned "authors") as well as a number of other members and "friends of the PPC" scattered around the world that have periodically assisted in gathering donated publications, as well as identifying and facilitating contact with potential university recipients. We note with pride that during 2013 we surpassed our 100 ton milestone, and are already nearing our goal of having shipped 200 tons of geoscience publications to universities around the world. Like the SEG's Geoscientists Without Borders®, the AAPG Publication Pipeline Committee is a global outreach program with roots in the petroleum E&P industry, and looks forward to exploring ways in which the two groups might collaborate going forward into the future.