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The paper demonstrates the possibilities of a scientometric approach using CiteSpace II software analysis of the field of railway dynamics with detection of research front, main clusters of cross-c...

The technological possibility of using titanomagnetite pellets produced from the iron of the Tebinbulak ore deposit for the production of sponge iron and its use in the production of hot iron has been investigated. Comprehensive theoretical and experimental studies of the Tebinbulak ore deposit were carried out within the framework of the state program of the Republic of Uzbekistan by JSC “Uzbekistan Railways” (Republic of Uzbekistan, Tashkent) together with Horst Wiesinger Consulting (Austria, Linz, “Horst Wiesinger Consulting” (HWC), GmbH) on the basis of the Research Center of University of Leoben (Austria, Leoben, MUL), Society for the Study of Iron Ore Processing (Germany, Liebenburg—Otfresen, SGA). A resource assessment with further approval of economically feasible recoverable reserves of the deposit in accordance with the international JORC Code, a complex of research works on enrichment, recovery and further processing in the metallurgical redistribution of ores of the deposit were carried out. The definition of an effective technological scheme, the determination of the vanadium extraction technology is a valuable material in various industries and has a high added value.

During field development of a microgrout for the stabilization of painted lime plasters detached from a limestone substrate, diethyl oxalate-based formulations out-performed microgrouts based on na...

A limited remaining reserve is one of the challenges commonly found in mature field development. Swamp fields in the Mahakam block is an example of mature field development which leads to a marginal operation. Delivering wells more economically is one of the key points to survive during those conditions. Rig operation with a significant daily expenditure could be a way for improvement to yield economic wells. In general, an efficient rig operation would deliver wells in a shorter duration and at a lower cost. In order to lessen the well duration, two aspects could be improved: performing co-activity operation to shorten the horizontal time (preparation) and mastering drilling practices to shorten the vertical time (drilling). In the co-activity operations aspect, various initiatives have been implemented, such as rigless operations, batch drilling, and offline or simultaneous activities. While in the drilling practices aspect, drilling parameters, bit design, connection practice, and team motivation were the areas that have been improved. This paper will elaborate further on those initiatives. Implementing massive co-activity operations and the best drilling practices have demonstrated a significant time saving of 24% for the shallow well (final depth around 1800 m) and 27% for the deep well (final depth around 4300 m) in the block. These practices have also made a new record of the fastest well completion in 2.17 days and the highest drilling ROP for 141 m/hour with drilling 2303 m in the first 24 hours. The record of most drilled length in 24 hours is the world best performance of RSS BHA as per Directional Driller Company worldwide record. As a result, the 2020 average cost of the shallow well was 2.6 MUSD while the deep well was 4.1 MUSD. Those massive co-activity operations and drilling practices have been properly executed since 2019 without any safety incident and related NPT. The positive results have helped the development project to survive in marginal conditions.

The paper has been prepared according to a Project of Grant Financing of the Ministry of Education and Science of the Republic of Kazakhstan 2018/АРО5131591.

The Liza Phase 2 Project combines a novel execution approach and forward-looking technology components to develop more complex areas of the Liza resource. The project delivers technology to optimize resource development through efficient Subsea, Umbilicals, Risers, and Flowlines (SURF) equipment designs and digital elements to enable future capabilities, such as a fiber optic cable to shore. For a new approach to Floating, Production, Storage and Offloading (FPSO) delivery, the project is partnering with SBM for the first ever use of their Fast4Ward® concept.The SBM Fast4Ward® program utilizes the Multi-Purpose Floater (MPF) hull design and provides the benefits of a new build FPSO with a reduced project development time similar to that of conversions. With almost double the SURF infrastructure as Liza Phase 1, Liza Phase 2 uses learnings and standardized SURF architecture to deliver one of the industry's largest subsea developments. Establishment of win-win partnerships with the primary contractors to achieve best overall value and strategic use of part number duplication contribute to the overall success.Based on the work of ExxonMobil proprietary reservoir modelling, infrastructure is being installed to enable Water Alternating Gas (WAG) injection for the complex development while a subsea fiber optic cable enables data to shore for optimized reservoir management and advanced facilities surveillance.The project is on track to deliver ~2 years after first oil was achieved for Liza Phase 1 by building on design replication and common methodologies where possible. Through thoughtful application of standardization, learnings, and incorporation of new technologies, the project efficiently delivers advanced capabilities to the Liza field. This also enables a "Design One, Build Multiple" (D1BM) approach for future developments in Guyana.

With increasing demand of subsea processing and surveillance goals Best-in-Class Operators are developing advanced subsea instrumentation and controls to challenge in the next decade: i) a cost-effective way to inspect and repair subsea complex facilities and ii) to reduce the downtime, possibly increase the production performance while preserving the integrity and maintenance of the assets. The so called "Autonomous Subsea Field Development" is a study triggered by an ExxonMobil URC (Upstream Research Company) initiative aimed to explore possible improvements and re-designs of subsea equipment considering the advancing capabilities of ROVs and new generation of Subsea Drones, and driven by the following questions: with the advancements in AUVs and ROVs, can subsea equipment be re-designed to take full advantage of the new capabilities? Can this re-design improve from different perspectives (Availability, Costs, Operations, etc.) a subsea field development? A dedicated study was conducted by SAIPEM to identify the value proposition, technology needs and gaps for future advancement by leveraging on the technological "building blocks" that could be integrated in a subsea field development scheme and on a field operational procedure. Within the study, seven different cases, distinguished by their status of advancement (from Brown to Green Fields) and by the level of penetration of Subsea Drones in the architecture, have been analyzed. A conceptual engineering process, based on the tenets of value engineering was conducted in a holistic fashion covering the full field development facilities during the life cycle in order to steer the conceptual engineering choices that could maximize the project value. Using a systemic Value Engineering approach based on the NPV equation, the study identified the main technological and economic impacts coming from the adoption of Subsea Drones on a current and future Digital Subsea Field exploring the following pillars: i) CAPEX, ii) OPEX, iii) AVAILABILITY, and iv) RISK. In the sequence of six cases investigated, it has been identified how these incoming "subsea capabilities" will be gradually implemented into redesigned subsea architecture and serviced in view of a new Life of Field concept.

The oil and gas industry faces many challenges as it is committed to provide energy to a world in transition. Declining prices impose constraints to new developments, either greenfield or brownfield. Additionally, the industry’s commitment to long-term value creation with reduced carbon footprint is confronted with the traditional solutions for well construction, production and processing, which consume significant amount of energy with corresponding high CO2 emissions. In this scenario, subsea production and processing technology has been a key enabler for the exploitation of oil and gas resources. This paper presents a holistic review of trends in subsea technology development over recent years which have direct impact on the heart of the subsea production system, namely the subsea tree. The technological developments considered are in different subsea applications such as robotic automation, communication systems, and all-electric systems. The objective of the ongoing research is to perform structural and fundamental analysis of subsea production and injection systems and address the question on how technological developments can be utilized to design an overall better subsea production system so the industry may fully benefit from the economic and ecological impact brought by the joint use of these technologies. Opportunities for reevaluating barrier philosophy to identify technical and economic opportunities for design simplifications of subsea trees that still leave enough pressure barriers in all operational modes are also considered. The analyses presented indicate the current stage of the examined technologies and their potential at reducing both capital and operational cost of subsea systems. These results will be the basis for the future evaluation of improved and new design solutions within the scope of the ongoing project performed by the Norwegian University of Science and Technology and its industrial partners.

During well planning, drillers and petrophysicists have different principle objectives. The petrophysicist’s aim is to acquire critical well data, but this can lead to increased operational risk. The driller is focused on optimizing the well design, which can result in compromised data quality. In extreme cases, the impact of well design on petrophysical data can lead to erroneous post-well results that impact the entire value-chain assessment and decision making toward field development. In this paper, we present a case study from a syn-rift, Upper Jurassic reservoir in the Norwegian Sea where well design significantly impacted reservoir characterization. Three wells (exploration, appraisal, and geopilot) are compared in order to demonstrate the impact of overbalanced drilling on well data from both logs and core. Implications for reservoir quality assessment, volume estimates, and the errors introduced into both a static geomodel and dynamic reservoir simulation are discussed. This case study highlights the importance of optimizing well design for petrophysical data collection and demonstrates the potential for value creation. Extensive data collection was initially carried out in both exploration and appraisal wells, including full sets of logging while drilling (LWD), wireline logging, fluid sampling, and extensive coring. Both wells were drilled with considerable overbalanced mud weights due to the risk of overpressured reservoirs in the region. The log data was subsequently corrected for significant mud-filtration invasion, with calibration to core measurements guiding the interpretation. Geological and reservoir models were built based on results from the two wells, and development wells were planned accordingly. A thorough investigation of core material raised suspicion that there could also be a significant adverse effect of core properties resulting from overbalanced drilling. The implications were so significant for the reservoir volume that a strategic decision was made to drill a geopilot well close to the initial exploration well, prior to field development drilling. The well was drilled six years after the initial exploration phase with considerably lower overbalance. Extensive well data, including one core, were acquired. The recovered core was crucial in order to compare the reservoir properties for comparable facies between all three wells. The results from the core demonstrate distinctly different rock quality characteristics, especially at the high end of the reservoir quality spectrum. Results of the core study confirmed the initial hypothesis that overbalanced drilling had significantly impacted the properties of the core as well as the well logs. The study concluded that the updated reservoir model properties would significantly increase the in-place volumes compared to the pre-geopilot estimate. This study shows how well design adversely affected petrophysical measurements and how errors in these data compromised geological and reservoir models, leading to a suboptimal field development plan that eroded significant value. This example provides a case study that can be used to improve the well design so that petrophysicists and drillers can both be part of the same value creation result. Future work will include further laboratory investigations on the effects of high overbalanced drilling on core and possible “root causes” for compromised core integrity.

Summary In article a karst as dangerous engineering-geological process is considered. It is discussed a question of karst typing on open mine deposits of gypsum plaster. In context of karst danger by morphological and morphometric parameters the karst typing is proposed, for example of Sokolino-Sarkaevsk deposit. Examples of practical application are given, which show, that modern impact and karst forms typing very largely allow to decrease a risk of human traumatism and technics damage at mining on the open mine deposits of gypsum plaster.

The ADNOC Offshore oilfield located in the Arabian Gulf is being developed utilising various wellhead towers, infield pipelines and a standalone super complex. The field development team devised an updated subsurface plan to achieve production targets beyond the original plan. The incremental oil necessitated assessment of original surface facilities design to identify any bottlenecks and unlock constraints. A set of production forecasts were initially provided as basis for assessment covering various scenarios and range of reservoir uncertainties. To manage these uncertainties, the facilities and subsurface development teams worked in an integrated and iterative way. The production profiles were used to assess and develop understanding of surface facilities such as oil flowline network, water injection supply and network, gas lift networks and the major equipment. The assessment results provided guidelines on the process facilities constraints which were feedback to subsurface team. An optimised subsurface development plan was then generated respecting the facility constraint and leveraging the existing facilities design to utilise ullages. An initial view of investment to produce incremental oil considered installing three new wellhead towers, a new manifold platform and a new water injection platform both linked to the super complex and a new main oil line installation to transfer partially stabilised oil from super complex to oil processing plant. The technical evaluations and the decision analysis resulted in a low-cost solution that was needed to ensure that the field's incremental oil production is economically viable. The integrated approach not only allowed selection of techno-commercial robust solution but also allowed optimisation of investment providing flexibility to accommodate the key project uncertainties. This was achieved by deferring the investment to future by descoping the overall development plan in two separate projects - achieve production plateau and sustain plateau. The interim period between the two projects would provide time to resolve the subsurface uncertainties and an opportunity to revisit future development strategy without committing any investment. In addition, the original UTC was significantly improved. This approach emphasised the importance of having a flexible surface facilities solution in accommodating the developments in the subsurface field development strategy especially in an offshore environment and during the early field production period. This paper presents an approach followed for optimisation of an offshore oilfield development plan under various surface facilities constraints.

Fixed offshore structures has predominantly been installed via the conventional crane barge, no matter whether it is small or a big structure. Utilization of a crane barge has resulted in a significant installation costs as the mobilization cost and the Daily Charter Rates (DCR) for the vessel is very high. Supporting the innovation agenda in an effort to better control project costs, the rig-installed platform concept is one of the option chosen to install small lightweight structure due to the cheaper cost of Jack-up Rig (JUR) day rates compared to a conventional crane barge. The savings in material, schedule and mobilization could be realized as the jack-up rig can proceed with the drilling of the wells (which are also the main piles of the structure) directly after the structure installation. As JUR is primarily used to drill oil/gas wells, some minor modification may be required to the JUR before it can be utilized to install small and lightweight offshore structures, both jacket and topsides, with some degree of limitations due to the drilling envelope and derrick lifting capacity. This ‘know-how’ has been around for quite some time in the industry by niche service providers, but was not regularly exploited in this part of the world as it has been a norm for the field development team to manage an installation contractor whilst the wells team manage a drilling contractor. This paper shares the learnings of a wellhead platform for a marginal field that was successfully engineered, fabricated and offshore installed using a JUR and eventually achieved 1st Oil within 9 months of contract award at an installed cost below USD 29 Million. This paper will mainly discuss on the pre-requisites of JUR installed platforms, case for change, concept select and potential value creation to the overall project. The project referenced above has exemplified to the industry that JUR installed platform is a feasible option in this part of the world, with significant cost savings, contributing to a better economics for a marginal field project.

Mobile mudmats are increasingly adopted as foundation solution for subsea structures in offshore field developments, to allow their horizontal movement under the cyclically imposed expansion/contraction operating loads from the connected lines. The foundation compliance grants the dissipation of the applied loads while the structure slides on the seabed and the required base dimensions are reduced. Foldable solutions can even be installed integrated with the related lines, passing through the pipelay vessel tower. The described experience is based upon design and installation of mobile mudmats for subsea structures in the last twenty years of activity in several deepwater areas all over the world. The design has been improved with time and its robustness has been demonstrated using alternative analytical approaches and Finite Element Model of the system with proper definition of soil-foundation behavior through equivalent springs. The geotechnical engineering effort focused to ensure the foundation adequate bearing capacity and its ability to slide under repeated thermal/pressure expansion loads during design lifetime, without developing excessive settlements and pitch/roll unacceptable rotations that could compromise the system performance. The purpose of the present work is to raise awareness of the need for reference international criteria for the design of mobile foundations, which represent an important solution for a subsea field development. Available Codes and Standards do not cover the relevant aspects of the mobile foundation engineering: they are based upon fixed foundation concept, which is expected to be stable under all the applied load combinations without developing any significant displacement. The mobile foundation engineering challenge is to accept that a failure mechanism develops in sliding condition while proper design criteria of system stability and reliability are fulfilled. Valuable and impressive research works have been carried out and published on the subject in the recent years. However, for practical application, specific criteria are required to provide a unique basic reference for design (minimum safety requirements/methodology/guidelines), which might be supported or not by more detailed and complex approaches, as occurs for traditional "fixed" foundations. Subsea structures could be regarded in the future as special components of the pipeline with a proper methodology to investigate their interaction with the seabed for the subsequent structural analyses.

Chemical injection in subsea fields is a consolidated practice to solve or prevent flow assurance issues that may occur linked to hydraulic, thermal and operability requirements, especially in transient conditions. The traditional approach adopted to supply chemicals to a subsea tieback is to position the chemical injection system, including pumps and storage, on the platform/FPSO, transporting the chemicals subsea through the umbilical or the chemical lines in case of high flow rates, and performing chemical distribution subsea up to the injection points. In the development of a long subsea tieback, costs for the umbilical system tend to increase based on its length and complexity. Moreover, pressure drops and control of chemical delivery pressures and flowrates through such a long umbilical can be extremely challenging, together with the risk of umbilical line blockages and their related issues. The design resolution to enlarge the diameter of the chemical conduits in umbilicals leads to an increase in unit weights and, combined with the umbilical length, additional costs and packing and installation challenges. These factors drive the need to review the conventional chemical injection system architecture and to make the development of a long tieback sustainable from the point of view of cost and technology. To overcome these major criticalities, the chemical injection system can be placed subsea, possibly close to the injection points. Recently, Saipem has mapped the typical chemical demand for a representative size oil fields, with the main aim of defining a subsea chemical injection system architecture and its related main components. The main result of this exercise is the definition of a configurable architecture for subsea chemical storage, injection and refilling facilities to be located close to the subsea users, based on operating consideration suitable for offshore and deepwater scenarios. A "building block" approach is followed together with a certain degree of equipment standardization, where possible, allowing for a flexible system that can be adapted and tailored to the specific field. Technology development status has been also considered and specific Saipem technologies, currently under qualification or being patented, have been considered and integrated in the concept.

This paper is part of the special OTC session "Floating Memories-Look Back to Leap Forward" intended as a historic retrospective of the evolution of the four major types of floating production platforms: Floating Production Storage and Offloading (FPSO), Semisubmersible (FPS), Tension Leg Platform (TLP) and Spar, from their inception to the present day. The session includes a look ahead to the future of these floating platforms and what it will take to sustain their commercial viability as they adapt to headwinds from continuous volatility of oil and gas prices and competition from onshore tight oil projects.This paper's focus is the Semisubmersible Floating Production System (FPS). It chronicles the forty five year progression of FPS technology from its humble beginnings in 1975 as a converted Mobile Offshore Drilling Unit (MODU) deployed on the Argyll field in the North Sea in 80 m of water, to Appomattox, the most recent FPS, that began production in 2019 in 2250 m of water in the Gulf of Mexico (GoM) . It also touches briefly on the evolution of the FPS hull, mooring and riser systems and addresses future trends and prospects.From Argyll to Appomattox

Economic success in the Cana Woodford shale play in Western Oklahoma has been largely due to field development using vertically fractured long horizontal laterals. In progressing from the field delineation phase, where sections are held by single well, to the field development phase, where multiple new wells are added to a previously produced section, many of the pre-existing “parent” wells suffer significant reduction in productivity as a result of interference from fracturing operations in the neighboring “infill” wells. We hypothesized that the change in the parent well's productivity was due to changes in fracture conductivity and/or changes in effective fracture length. In order to investigate the validity of our hypothesis, we developed a novel high-resolution spectral gas reservoir simulator to determine whether we could mimic the observed production behavior in the field. In particular, we wanted a simulator that would be immune to spatial truncation errors associated with finite difference schemes, and which would allow us to clearly examine interaction between nanodarcy reservoir matrix and high permeability narrow fractures; in addition, we needed the ability to alter fracture permeability with time to simulate the hypothesized effects of fracture interference. This paper details development of the spectral simulator and demonstrates that changes in fracture conductivity and length due to the interference event can account for observed productivity changes. We qualitatively compare simulator data to observed field data and show that changes in well productivity due to fracture interference can be explained by alteration of fracture half length and/or fracture conductivity.

Over the years, waterflooding has been the most widely used secondary oil recovery method after the exhaustion of the primary depletion energy of the reservoir. Waterflooding schemes have to be planned such that at every point of the operation, net income from oil recovery exceeds operating expenditure of which produced water disposal cost is paramount. Hence, engineers are regularly plagued with challenges such as optimal completions zones for injectors and producers, optimal flood pattern to adopt and number/type of producers and injectors to use in waterflood field development so as to improve oil recovery, but reduce water production. The aim of this study is to optimize waterflooding from a case study model using reservoir simulation techniques. A simple optimization methodology involving the analysis of the effects of zones of production and injection, pattern of waterflood selected and number/type of producers and injectors on cumulative recovery from a waterflooded reservoir was used. Results revealed that (1) pressure maintenance/increment is more effective when there is water injection into more zones of the reservoir, (2) for waterflood operations involving the use of vertical injectors, higher water production was observed because water is expected to flow more conveniently in the upward direction due to gravity rather than laterally and (3) with horizontal injectors, higher cumulative production was achieved especially for cases where water is injected into the same zones from which oil is produced.

Many optimization schemes have been proposed to simultaneously optimize various variables such as well locations, well operation schedules, well types, and the number of wells. However, most of these approaches often focused on fixed well type without considering conversion of existing wells. This paper proposes a new optimization for mature oil field development. Since converting from producers to injectors is a common practice in mature oil field, we have to optimize simultaneously type conversion schedules of all existing producers and infill wells as well as the number of infill wells, their locations, and operation schedules. We propose a new hybrid algorithm, which combines differential evolution (DE) algorithm and mesh adaptive direct search algorithm (MADS) to solve our optimization task. By considering well type conversion, it will increase the complexity of searching space but provide more realistic and optimal development plan. We demonstrate it in 2D synthetic and 3D PUNQ-S3 reservoirs for optimal field development. The proposed optimization considering well type conversion provides higher net present value than the fixed well type optimization in the both cases. The hybrid algorithm also shows better search performances than DE and MADS algorithms. Thus, we conclude that consideration of well conversion schedules is necessary for economical field development scenarios in mature oil fields.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30721, “Floating Offshore Windfarm Integrated Into Subsea Field Development: Case Study of the Saipem Windstream Concept,” by Benjamin Mauries, Giorgio Arcangeletti, SPE, and Christophe Colmard, Saipem, et al., prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4-7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. Operators are moving active production and injection equipment onto the seabed with the aim of reducing capital expenditures (CAPEX) or topside space requirements. Moreover, they want to minimize new production floating facilities. Given this scenario, overall electric power needs may become an issue because of the extra power demand caused by the increasing number of electric consumers placed subsea. The complete paper discusses a floating wind-turbine solution that is particularly cost-competitive for deepwater locations and that can unlock the possibility of deploying large wind-powered generators far from the coastline in deep water. Introduction Saipem launched an initiative aimed at finding a solution for management of subsea field power demand bearing in mind two primary considerations: Minimize CAPEX by reducing the distance between the subsea-field production location and the topside equipment supporting this production Decarbonize the field by adopting a renewable energy source Concept Background and Potential Application The operator has developed a floating substructure technology for offshore wind farms known as HexaFloat. This concept uses a minimal floating hexagonal tubular substructure supporting wind-turbine tower and providing necessary floatability. The substructure is connected by tendons to a basket counterweight filled with solid ballast providing stability with pendulum-restoring forces. The assembly of the basket and the substructure behaves as a rigid body if all tendons are loaded. This assembly provides flotation with excellent stability thanks to the distance between the center of gravity and the center of buoyancy. Because this stability is provided by weight, large hydrostatic stiffness is unnecessary. As a result, only the central cylinder is exposed to the wave energy. The whole floating system can be anchored with three to six low-tension mooring lines, depending on environmental conditions.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 195951, “Case Study: Optimizing Eagle Ford Field Development Through a Fully Integrated Work Flow,” by Adrian Morales, SPE, Robert Holman, and Drew Nugent, Chesapeake Energy, et al., prepared for the 2019 SPE Annual Technical Conference and Exhibition, Calgary, 30 September-2 October. The paper has not been peer reviewed. An integrated project can take many forms, depending on available data, from a simple horizontally isotropic model with estimated hydraulic fracture geometries used for simple approximations to a large-scale seismic-to-simulation work flow. The complete paper presents a large-scale work flow designed to take a vast amount of data into consideration. The work flow can be scaled for projects of any size, depending on the data available. Introduction In 2017, Chesapeake Energy launched an investigation to evaluate ways of improving overall recoveries within the lower Eagle Ford. Two theoretical approaches were generated to optimize the company’s development plan: modification to current completion designs to achieve greater near-well fracture complexity and modification of targeting strategies to more-effectively drain the Eagle Ford interval. Methodology To evaluate these approaches, the company acquired multiple data sets to provide an integrated study. An already developing and productive area was selected in southwest Texas to examine completion design and targeting strategies while attaining a data set to allow for complex completion monitoring and reservoir simulations to aid in subsequent development optimization while maintaining at least type-curve production. Microseismic was acquired on three wells with multiple downhole arrays used to visualize how fracture geometries were affected by completion design changes. For quality control, data from ultrasonic image tools, cement-bond logs, and gyros were acquired to increase confidence in microseismic results. Time-lapse 2D lines were acquired pre- and post-hydraulic fracture to measure seismic changes induced by completions. Water- and oil-soluble tracers were run to determine hydraulic fracture extent and drainage footprint. Parent wells were instrumented with surface pressure gauges to characterize hydraulic fracture hits. With permanently installed fiber, a post-hydraulic fracture downhole camera was run to examine cluster efficiency per completion design. Core and quad-combo logs were taken in the area to analyze compositional similarities in oil signatures compared with produced oil and to calibrate petrophysical and geomechanical values. Oil samples were collected and analyzed to derive an equation of state for fluid characterization and reservoir simulation. Natural fracture characterization was performed to determine the pre-existing geological fabric of the rock using lateral electrical borehole images, a field outcrop study, and quad-combo and fracture-identification logs derived from drilling data. Multiple facture calibration tests were collected in the study area at different target intervals to calibrate vertical stress profiles and examine reservoir pressures. Lastly, following 1 year of production, a temporary rod-conveyed fiber-optic production log was run to determine cluster contribution based on completion design. The independent data sets were integrated on a common commercial software platform for geomodel creation, discrete natural fracture characterizations, hydraulic fracture simulations, and reservoir simulations. An integration strategy was developed to bring together the vast amount of data acquired. The work flow is a simplified representation of the data interdependencies and was used throughout the study. Only five data acquisitions are shown to overlap; however, any change in interpretation can lead to revision and iteration of several interdependent segments.

The paper provides an overview of digital oilfield development experience gained by Nafta College [1] employing the complex PolyPlan asset simulator during a multi-year programme of PetroCup [2] interactive tournaments. During the last few years, professional multi-disciplinary teams of 8 to 10 people from petroleum organisations based in various countries carried out few-days exercises on production and development of synthetic assets. In total, more than 20 petroleum companies, 10 petroleum service companies and 10 academic and research institutions have taken part in this programme. PetroCup sessions had various team structures, digital reserves and regional economics to ensure realistic production conditions. Despite this variation, some statistical metrics highlight dominant trends in oilfield development strategies, including effective and ineffective ones. The results may attract interest from petroleum asset managers to assess the efficiency of corporate strategies and policies in field development planning and well and reservoir management, and eventually increase their performance. The provided statistics are useful for managers of petroleum companies to assess the range, perspectives and value of production-related services. The PetroCup statistics can also be used by training centres and universities as an indicator of upstream trends and for maintaining the right focus in petroleum engineering curricula.

This paper presents various case studies of projects in Gulf of Mexico and West Africa, which demonstrate how innovative jumper mounted flow access technology was successfully adopted to provide a differentiated field development strategy based on standard subsea hardware while still accommodating production enhancing technologies across multiple subsea field developments. The paper also will explain how the technology supports fast track, cost effective subsea tiebacks, by promoting standard equipment and allowing concurrent hardware deliveries to deliver first oil faster. The paper will share client considerations regarding standardization of the main subsea hardware elements, subsea system flexibility and the existing solutions for measurement and intervention packages, such as multiphase flow meters. Project critical paths typically dictate that technologies such as flow meters must be available to synchronize with XT, manifold and jumper manufacture, testing and installation. Thereafter, any retrofit or rework requires significant operational downtime to recover and replace that element of the subsea system. Integrating the retrievable flow access module (FAM) technology into subsea architecture within the jumper envelope addresses these concerns. Promoting standardized XT and manifolds on a field or regional basis, while the FAM technology provides the flexibility to address the individual well production requirements. Further explanation will be provided as to how operators can use the technology to maximize ultimate recovery by accessing a suite of technologies throughout the life of field for both new greenfield and existing brownfield applications. Technologies such as, flow measurement and control, well and flowline hydraulic intervention and remediation, well production pumping and compression, pre-commissioning and secondary well control. Finally, the paper considers the strategic benefits of adopting the flow access technology for subsea field development, promoting subsea system standardization, Capex, schedule and risk reduction compared to the more typical alternatives.

Technology advancements steer implication of automation in the cognitive functionality of reservoir management, emerging chiefly in optimization and its peripheral concepts. Smart field development has been modeled upon real-time management, consequently, closed-loop management has taken a step further integrating data assimilation and optimization in a near-continuous process. Nevertheless, automation in planning domain threats the concealed concept of Situation Awareness (SA) which is a predominant planning concern in complex dynamic systems. SA incorporates the perception of environmental elements and events, the comprehension of their meaning, and the projection of their status in future to make conscious decisions. In current practices of smart reservoir management, evaluation of reservoir status and setting-up future goals are temporally accomplished upon interactions of engineers and simulation optimization. However, this traditional effort to preserve SA upon human interference results in descent of automation and suspension of its demonstrated beneficial advantages in real practices. An effective and practical automated reservoir management should self-sufficiently consider SA in automation mechanism. In this paper, the goal is to present an innovative theoretical model of automated reservoir management, which considers SA as a mindful gadget that pertinently define multi-objective optimization problem, regarding reservoir dynamic situation in line with economic, technical and operational managerial targets. The proposed model is compatible with previous models and moreover supplements them with a conscious automatic planning potential. Utilizing this model, multi-objective optimization will provide higher level of automation upon definition of temporal objectives and preferences without human interference. This model introduces higher degree of freedom in decision making and generates production/injection profiles flexible with predefined objectives and preferences of the management, which is advocated through a case study of water injection reservoir. Conceivable sets of dynamic objectives in different optimized production/injection profiles illustrate the establish role of SA in automatic reservoir management.

An application of integration of reservoir production data in analysis for nature of fault is presented in this paper. The real data of a Gas Field (namely RS Gas Field) of L-Basin of Pakistan are used. The basic concept behind this work is to enlighten the importance of production data analysis in a broader way like for finding out the nature of fault i.e. conductive or non-conductive and if it is conductive, what is the leakage factor of the fault etc. Normally in the case of fault analysis we rely on geological and geophysical methods to some extent but in some cases where these geological and geophysical methods are not able to reach any final and firm conclusion because of data limitation or any other reason, production data analysis may play a great role in answering the ambiguities regarding any fault/faults present there. This paper describes the successful implementation of reservoir production data analysis in RS Gas Field where the main uncertainties were identified during initial stage of field development when location of new development well was going to be marked. Numbers and locations of well are important factors of Oil and Gas Filed Developments; but specifically, for Gas Field Development, these factors become more crucial as compared to Oil Field Development; so clear knowledge of any heterogeneity, barrier, boundary or fault is necessary to develop a gas field optimally and economically.

Summary The amount of information available for field-development planning is limited, forcing the production strategy (PS) to be designed with a great amount of uncertainty. During its implementation, new information allows the adaptation of the strategy for economic gain. This work reproduces the field-development process under geological uncertainty in case study UNISIM-I-D (benchmark case that is based on Namorado Field in Brazil). The main objectives are to evaluate the process and to observe the evolution of risk curves, all in a controlled environment with real-field features. The methodology generates new geostatistical images on the basis of new well logs, assimilates production data with an ensemble-based method, and reoptimizes the PS with a hybrid algorithm. The field development is carried out by repeatedly applying this framework with human supervision. Each step is customized with algorithms to simplify the implementation and to reduce computational effort, making this methodology more appealing for practical use. New data are collected from a high-resolution reference model that does not belong to the ensemble of models. The process starts with a PS, previously optimized under the uncertainties of the case study, which yields the real economic outcome within the original uncertainty range. Results show high-quality history matching (HM) that excessively reduced the risk range and the variability of the updated model sets. Optimizations on the PS, on the basis of the updated ensembles, consistently increased the expected monetary value (EMV) of the project without guaranteeing an increment in the real net present value (NPV). Applying the methodology repeatedly throughout the field development increased the EMV by 29% (from 1.532 to 1.975 billion USD), whereas the real NPV decreased 2% (from 1.346 to 1.319 billion USD), falling out of the expected range and revealing that the model sets did not fully represent the real field. The lack of good representation is aggravated by heterogeneities inherent to the unknown reservoir, which are difficult to identify with only well logs and production data. The results from the application of a closed-loop reservoir-development process in a controlled environment warn against similar hidden mechanisms happening on real-field developments under similar circumstances. They reveal intrinsic pitfalls in reservoir modeling that may contribute to production-forecast problems and call for a reflection on how reservoir uncertainty assessment is performed. We prove that large sets of models do not guarantee coverage of geologic uncertainties because they do not fully represent the real reservoir. The field-development process naturally changes the risk curves, contributing to revealing the lack of representation.

The article is devoted to the peculiarities of the field development X, defined efficiency of geological and technical measures in the oilfield.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 181707, “Truly Sustainable Building Blocks for Deepwater-Field Development: Need for Strategy Redefinition in a Persistently Low-Oil-Price Scenario?,” by Francesco Beltrami, Energo Engineering, and Kevin Hansen, Granherne, prepared for the 2016 SPE Annual Technical Conference and Exhibition, Dubai, 26–28 September. The paper has not been peer reviewed. To survive the current economic scenario, the deepwater industry needs to rethink the way projects are carried out. This paper reviews clusters of information that will be termed “building blocks” for deepwater-field-development planning, discussing how they are currently used and exploring more-affordable, but technically robust, alternatives. Building Blocks Advantages of Building Blocks. The use of conceptual “building blocks” during concept definition and concept selection is not new; they have been used in field-development planning for more than 3 decades. The field-development building blocks are a very versatile and powerful tool and are relatively simple to define and to use. They may be tailored to the case under investigation, providing a higher-level view or more-detailed insight, and can enable rapid generation of several development options. They also offer the possibility of producing simplified sketches representing field-development options (Fig. 1). The key components of a future offshore field development are represented by predefined, project-specific building blocks that are combined in a methodical way (often automated) to generate multiple development options to be further ranked and screened. A typical building block is the type of host required in an offshore-field development. Multiple alternatives are possible, such as the floating production, storage, and offloading (FPSO) vessel; the semisubmersible; the spar; the tension-leg platform; and other fixed or floating platforms. Even a limited number of initial building blocks can generate a remarkable number of field-development options. To manage the potential complexity of the building-block approach, the quantity and type of building blocks to be used are generally defined in an early stage of the project. Specific building blocks may be added to ensure that project challenges are addressed properly. Building blocks may be purely qualitative or may provide some quantitative information. In some cases, there might be multiple combinations of technical and nontechnical features for a single building block. In some geographical areas, the FPSO would necessarily have to be disconnectable; this requirement would affect the definition of the building blocks to be used.

In the current period of industry downturn, creating and executing opportunities to develop an offshore brownfield has become more economically challenging. This paper describes the technical, commercial, and operational aspects that helped in achieving an established economical cut-off for project sanction. The project will enable sustaining field average oil production above operational economic limits thereby maximizing field life. With the prevalent low oil price conditions, the economic threshold for projects sanction and execution has reduced. The asset team faced a challenge to achieve a UDC threshold of USD16/bbl. Multi-disciplinary team was tasked to look at key aspects to improve project commerciality. Subsurface recovery potential was assessed thoroughly to evaluate the impact of subsurface uncertainty, and evaluate the impact on well designs on the project cash flow. Wells were designed to tap multiple reservoir targets to minimize subsurface risk through existing facilities to maximize ullage. The wells were drilled from new slots via small deck extension instead of the high-risk slot recovery option, which helped to reduce the Capital Expenditure (CAPEX). Fit-for-purpose and cost optimized wells were designed by minimizing automation (i.e.: ICVs, PDGs, etc.) which also reduced operating risk and cost. Multiple sands were targeted in different compartments with different pressure system, hence planned not to commingle production. Hence, only one primary reservoir was completed, with other zones kept behind casing for future intervention with bottom-up production strategy. This helped deferring the project investment as this was in the intervention cost in Operating Expenditure (OPEX) which helped to improve the project economics. Further cost savings were achieved by accelerating the project in order to achieve synergy with an upcoming drilling campaign. The reduction of the overall project CAPEX, thus allowed the project to be commercially feasible and technically sound for execution. In addition, the team has also established a reservoir management plan with mitigation plan to deal with the main subsurface and surface risks. The out of box solution of optimized field development plan for complex offshore brownfield with limited facilities modification, while being cost conscious but still ensuring technically sound concept proved to provide the answer for sustainable production growth in S Field at low oil price environment. This paper will also highlight the key lessons learnt and obstacles which were observed during the execution of the project are expected to become guidelines for future low cost projects in this region.

There is a global trend for integrated subsea alliances to be involved in projects earlier, with a broader scope and in closer collaboration with the operating company. Sometimes, this is achieved by enabling contractors to develop and propose their own field development concept, known as a supplier-led solution (SLS). This paper refers to a case study that demonstrates an effective way to improve project economics. A benchmark field layout plan was first generated using the customer's reference case. Then, a fully unconstrained SLS was developed to challenge and improve this reference case based on six main factors: Integrated production system modelling Fit-for-purpose project and design scoping Alternative field architecture Use of standardization Use of supplier or industry specification Integrated project execution A production assessment, cost estimation, and schedule were developed first for the reference case, fully compliant with the customer specifications, and with no deviation to the scope of work, and second, for the completely unconstrained SLS. Comparing the SLS to the reference case for this case study, the main improvements were as follows: Accelerated production thanks to integrated modelling and the introduction of subsea boosting technology Significant improvement in capex of approximately 41% Accelerated schedule due to a proposed innovative bidding process and a reduced equipment lead time enabled by standardization Lower project risk profile by improving the execution predictability primarily due to the integrated subsea offering The combination of these improvements resulted in better project economic viability and allowed lower contingency cost accruals due to proactive risk management. The SLS also helped the operating company to build a viable development scenario in order to pass through the next project stage gate. This paper demonstrates how an integrated subsea alliance with a broad spectrum of capabilities from the reservoir to the surface can deliver value through fully integrated earlier engagement. The methodology presented in this paper can be customized for any offshore prospect; the only prerequisites are early engagement, access to required data, and the freedom for the contactors to develop their own solution, in coordination with the operating company. A key feature of the proposed methodology is to link the SLS to reservoir representation, which avoids the common pitfall of delivering capex savings at the expense of larger production (revenue) losses.

By all accounts, Malikai is a marginal field – limited reserves in challenging reservoirs, remote from existing infrastructure and in 500m water depth. The field was discovered in 2004 and initial concepts based on a standalone development were not economically viable. The fact that it is now a producing asset is a success story built on effective collaboration, innovation and discipline execution. Shell with its JV partners (Conoco Philips, PETRONAS Carigali) reviewed the original field development and made the key decision to have Malikai as a satellite development to their Kebabangan production hub. To further reduce capital investment, the project team had to look at fit-for-purpose technical solutions (e.g. use of single casing combo top tensioned risers, tender assisted drilling). The tendering strategy allowed for maximum input from the industry while maintaining a design that remains compliant to Shell's proven deepwater design guidelines. It goes without saying that staying to cost and schedule promises took on a much heavier emphasis. Management of Change was strictly enforced. Similarly, with contract management. Key resources from Shell's center of excellence in Gulf of Mexico were mobilised to lead and deliver key components (tendons, risers). Others were on hand to provide advice and technical assurance on critical activities (integration, offshore installation, etc.). Local content and technology transfer were always important differentiators to Shell's operating model in Malaysia. This is clearly demonstrated in the make-up of the project team including its leadership. Goal Zero is a watch word especially at the main fabrication yard. The project recorded 25 million man-hours without any serious, lost-time injury and thereby keeping well below the Company's set targets. As a result of all the efforts, Malikai registered its proud place in oil and gas records as the 1st TLP for Malaysia and Shell's 1st outside Gulf of Mexico.

Summary In-situ upgrading process (IUP) is an attractive technology for developing unconventional extraheavy-oil reserves. Decisions are generally made on field-scale economics evaluated with dedicated commercial tools. However, it is difficult to conduct an automated IUP optimization process because of unavailable interface between the economic evaluator and commercial simulator/optimizer, and because IUP is such a highly complex process that full-field simulations are generally not feasible. In this paper, we developed an efficient optimization work flow by addressing three technical challenges for field-scale IUP developments. The first challenge was deriving an upscaling factor modeled after analytical superposition formulation; proposing an effective method of scaling up simulation results and economic terms generated from a single-pattern IUP reservoir-simulation model to field scale; and validating this approach numerically. The second challenge was proposing a response-surface model (RSM) of field economics to analytically compute key field economical indicators, such as net present value (NPV), by use of only a few single-pattern economic terms together with the upscaling factor, and validating this approach with a commercial tool. The proposed RSM approach is more efficient, accurate, and convenient because it requires only 15–20 simulation cases as training data, compared with thousands of simulation runs required by conventional methods. The third challenge is developing a new optimization method with many attractive features: well-parallelized, highly efficient and robust, and with a much-wider spectrum of applications than gradient-based or derivative-free methods, applicable to problems without any derivative, with derivatives available for some variables, or with derivatives available for all variables. This work flow allows us to perform automated field IUP optimizations by maximizing a full-field economics target while honoring all field-level facility constraints effectively. We have applied the work flow to optimize the IUP development of a carbonate heavy-oil asset. Our results show that the approach is robust and efficient, and leads to development options with a significantly improved field-scale NPV. This work flow can also be applied to other kinds of pattern-based field developments of shale gas and oil, and thermal processes such as steamdrive or steam-assisted gravity drainage.

Since the end of 19th century, two-phase hydrocyclone has been applied widely, owing to its high efficiency, small footprint and simple operation. However, two-phase hydrocyclone cannot meet the requirement of production, especially the demand of three-phase separation in oil-gas field development, such as separating associated gas and drilling fluid treatment, which accelerated the three-phase hydrocyclone development. From the beginning of 1990s, different types of three-phase hydrocyclone have been developed with little application and research. Through a brief introduction of three-phase hydrocyclone type and present technical situation, this paper analyzed the deficiencies of different three-phase hydrocyclone and came up with suggestions for improvement.

Drilling is one of the most costly and risky activities in oil and gas reservoir exploration and field development. A portion of this high cost is related to unwanted vibrations of the drillstring. With the advancement of “Measurement While Drilling” (MWD) tools and their real-time implementation, vibration models are still a valuable tool for pre-drilling analyses, designing the “bottomhole assembly” (BHA) and sensitivity analyses of the input parameters. In the last 70 years, a wide variety of models has been developed for design and analysis of drilling structures. Due to the complexity of downhole interactions and excitations a variety of modeling simplifications and assumptions is typically made. This paper presents a broad survey of the drillstring vibration modeling literature. The state-of-the-art of models for predicting axial, torsional and bending vibrations (uncoupled and coupled), boundary condition assumptions, equation formulation methods, and applications to vibration mitigation is reviewed. Moreover, the challenges of drillstring vibration modeling in the presence of modern drilling techniques such as deviated drilling and use of vibrating downhole tools are discussed. This survey is intended to organize and summarize the vast amount of literature in the field, and to aid engineers in both industry and academia in developing, choosing, or critically assessing the limitations of drillstring vibration models.

Since Deepwater field developments started around year 2000, Deepwater Buoyancy has been dominated by syntactic foam and has not evolved significantly since then. Some Deepwater applications like towed Bundle, Steel Lazy Wave riser and Hybrid Riser towers require large amounts of it, both for temporary (installation aids) use and permanent use, becoming a significant part of the cost associated to those systems. In parallel, the present market conditions is pushing Oil companies to develop new technologies and to promote cost reduction initiatives. In this context, Subsea7 and Matrix, Composites & Engineering have developed a new concept of buoyancy, so called low cost buoyancy. This paper will present the Buoyancy concept, will provide insight on the qualification tests successfully passed, and present typical application where the low cost buoyancy is intended to be used.

Achieving consistent optimum field development choices in technically complex portfolios requires sound individual and corporate technical capabilities. Within the largest Exploration and Production Company in the Sultanate of Oman, some key gas and contaminated hydrocarbon Field Development Plans are produced by dedicated specialized study teams that are part of the company's so-called Field Development Centre. In order to tackle projects involving technically complex challenges such as tight reservoirs, rich gas condensates, contaminated hydrocarbons or high pressure developments, a number of organizational elements are put in place to ensure continuous growth of staff and corporate capabilities along with corporate knowledge dissemination. First, each project team remains integrated throughout its project life time. The integration of subsurface and surface disciplines allows early identification of realistic and robust development options. It also facilitates knowledge sharing with activities such as field visits conducted jointly between subsurface and surface engineers. The benefits of this integration are demonstrated with examples from several gas condensate and sour oil study cases. Second, experienced professionals provide project specific guidance and coaching to junior staff over several projects. This scheme allows maximizing the impact of the experienced staff while allowing hands-on learning from younger recruits. Third, benefiting from a ring-fenced organization to conduct studies facilitates the retention of corporate knowledge and the replication of best practices. However, this does not imply that knowledge and capabilities remain centralized as several conduits are in place to ensure dissemination across the organization. Asset staffs with identified technical development gaps are assigned for the duration of a project to the study team where they actually develop their skills through direct project contribution. Specialized forums, physical and web-based, are also available to share information and solutions learnt from previous projects. Finally, fundamental technical capabilities and knowledge bases are developed at corporate level in order to consistently address key challenges encountered in various assets (e.g. gas condensate modeling and optimization, tight units recovery improvement, fraccing optimization and associated production forecasting). A wide scope integrated multi-year project covering all company gas activities within several formations has been kicked-off for this purpose. This fundamental project involves various contributors from the company such as Subject Matter Experts and experienced asset staff, specialized external service providers and academia. More specifically, the project aims at developing a comprehensive corporate understanding of its gas reservoirs, and at developing consistent datasets and validated effective modeling workflows to be disseminated through standards, websites and trainings. This paper provides an overview of the work practices and tools that have been put in place within a large company in order to ensure the steady development of staff and corporate technical capabilities while consistently addressing the development of its most complex oil and gas reservoirs.