Kuwait Oil Company (KOC) offshore exploration and development plans are underway to boost its production capacity to the future target rate. However, the selection of offshore field development scheme is critical due to the associated flow assurance risks, which impact project economics, safety, and sustainability. The objective of this study is to simulate and evaluate two offshore field development schemes, namely subsea multiphase flow, and platform schemes. The evaluation is based on the associated flow assurance risks, project economics, and environmental impact of each development schemes. The analysis covers simulation of each scheme, prediction of flow assurance risks, and prevention/mitigation of the risks during the entire life of the field. Results revealed that although the flow assurance risks in the subsea multiphase flow scheme are significant, it eliminates the large investment cost of platform, which improves the project economics significantly, and minimize environmental impact. Conversely, although the platform development scheme has low flow assurance risk, platform capital investment cost may impair the project economics, safety, and environmental impact. This study investigates each scheme by simulating, economically evaluating, and environmental impact assessing both schemes, to enable the right decision and selection of field development plan.

This paper is an introduction of a new hybrid plastics processing technology known as NNS (Near Net Shape) Technology, that demonstrates significant cost savings in the production of CNC (Computer Numerical Control) machined advanced engineering plastics parts by combining injection molding and CNC machining. The cost savings of NNS technology and the process is demonstrated with manufacturing examples comparing the traditional process of CNC machining parts from stock shapes such as sheet, rod or tube to the NNS technology process. Included in the examples are detailed production case histories with data supporting significant material cost savings and reduced machine time that are possible when NNS technology is utilized. NNS technology not only reduces the cost of producing CNC machined plastic parts but gives engineers the option to specify even higher performance plastics that can offer greater life in application. Plastics that offer improved chemical resistance, higher operating temp capabilities, and higher mechanical properties can now be specified that may have been cost prohibitive in the past with traditional CNC machining. NNS allows for initial lower part costs and more importantly lower cost-in-use with improved performance in the application. Common applications that can benefit from NNS include high performance plastic bearing and wear components, structural components, electrical insulating components and numerous other components across a wide range of oil and gas applications from onshore, downhole, offshore and subsea. Not all CNC plastic parts can benefit from NNS technology. We share the guidelines that we have found successfully help engineers to identify those parts that can benefit from NNS technology to reduce the production cost of CNC plastic machined parts for Oil & Gas applications.

This is one in a series of papers in the technical session, "Floating Memories – Look Back to Leap Forward." The paper focuses on the evolution of ownership and the financing model for upstream and midstream infrastructure in deepwater. It provides an historical perspective on the value chain, starting in the 1990s when offshore oil companies owned and operated entire infrastructures. As industry matured, pipeline companies and service providers began taking ownership positions in partnerships with the operators. Most recently, private equity has stepped up to invest in infrastructure, using creative financing models now in play.

The objective of this study was to evaluate the role of strategic mergers and acquisition (M&A) as a panacea for success of marginal oil fields development in Nigeria and to make recommendations for policy decisions. Data for the study were obtained from literature review, document analysis and multiple case studies from operating marginal oil field companies in Nigeria. The cases of Platform Petroleum, Sheba Petroleum, Seplat and others were investigated and analyzed. These case studies identified how marginal field operator's utilized mergers and acquisitions in the form of business restructuring, consolidation, strategic alliances, joint venture formation and partnerships as a development support strategy to remain competitive in the oil and gas industry. Other mergers and acquisitions activities by other companies were also examined. The study findings revealed that strategic mergers and acquisition is one of the survival options for marginal field operators in Nigeria. Mergers and acquisitions enhances the business growth for the marginal oil fields operators by expanding the opportunity for raising capital required for oil and gas operations and provision of larger equity base; including provision of access to technology and manpower. As the oil price in the global oil and gas market remains low, investors in oil and gas business are looking for ways to cope with the fall in revenues. In this dynamic business environment, one fact remains unchanged, marginal oil field operators in Nigeria must re-strategise in order to survive. The marginal oil field operators in Nigeria are encumbered by inadequate funds and other constraints such as lack of capacity, low volume of production and inadequate technology, therefore they have to adopt one of the critical success factors for business survival in a challenging environment. Herein lies the role of strategic mergers and acquisitions. The findings of the study will serves as a decision-making frame work for investors in oil and gas business wishing to participate in the sustainable management of marginal oil field in Nigeria. The study recommendations indicate that policy makers in Nigeria should create a favorable investment climate among which are: stable macro-economic policies, legal system that allows contracts to be enforced and clearly support access to channel of arbitration.

This paper presents the successful delivery of Jitang Field Development project, a marginal field located offshore Peninsular Malaysia. Vestigo Petroleum Sdn Bhd (Vestigo), a wholly owned subsidiary of Petronas Carigali Sdn Bhd (PCSB) as operator of the field has set-up a new benchmark in Malaysia when Jitang field commenced production in January 2020: The first in Malaysia to leverage on existing surface facilities via re-using/relocating Wellhead Platform (WHP) Commenced production within 13 months from project's Final Investment Decision (FID) Utilising suction pile technology and novel transport and installation (T&I) methodology to relocate the substructure and topsides of the WHP in a single piece from original to new location Development of Jitang field consists of a WHP, an FPSO and a flowline evacuating full well stream from four wells. This paper will focus on WHP as the relocation of the WHP is the main feature and key driver of the project. Technical due diligence effort that was done in mitigating risks are also emphasized. Vestigo's experience of re-using an existing WHP upon decommissioning the facility and re-installing it at a new location for re-use; proven that the concept works for effective solution of marginal field development. Jitang project has demonstrated significant improvement in project delivery schedule and cost saving.

The sheer size of the 2.7-billion-barrel field and expected operations of more than 50 years, make Johan Sverdrup an exciting place to develop the solutions of the future. As such, the Johan Sverdrup field development has been called the digital flagship for the operator. Being a ‘flagship’ means Johan Sverdrup is not only meant to be a vehicle for digital innovation to improve safety, value-creation and carbon efficiency for the field itself, but the field development is also meant to drive digital solutions and ways of working that have the potential to be scaled-up for the benefit of the operator as a whole. This paper starts by setting out the main digital focus areas for the Johan Sverdrup development, but drills down on exploring the areas where Johan Sverdrup is demonstrating real and tangible impacts already today. Examples include efforts to mature technology for automatic production optimization, a number of new pipe and seabed technology solutions (including fiber-optic PRM, fiber-optic monitoring of wells), and the step-wise development of a digital twin for Johan Sverdrup that will gives the opportunity to model and visualize key parts of the field. The paper describes the ‘digital field-worker’ at Johan Sverdrup which is changing the way of working, both during the construction and completion phase, but also during operations. This ranges from efforts to automate and digitalize work processes offshore to more innovative solutions. Examples of the latter include Echo – a multi-player digital twin solution allowing real-time visualization and collaboration between onshore and offshore – as well as the iterative development of anomaly detection models (utilizing machine learning and artificial intelligence) to move from condition-based monitoring towards predictive maintenance.

PNPR cluster consists of three fields, namely PX, NX and PR (combined STOIIP ~200 MMstb), located ~300 km offshore of Peninsular Malaysia. Throughout its journey of monetizing marginal waxy crude, many challenges and hurdles have arisen, including sustaining oil production rate above economic threshold, pipeline clogging, and FPSO fuel uncertainties, which requires collaboration between surface and subsurface team to develop unique solutions in managing these downturns. Critically, PNPR cluster is expected to reach economic limit within few years’ time. This paper will elaborate on how IOR is achieved in PNPR cluster, historically and in near future. Ever since first production by PX and NX in 2004, infill drilling campaigns have been needed to sustain production above the economic limit of 5,000 bopd. Later in 2009, approximately a year after PR kicked off its first oil; the14 km pipeline to FPSO was plugged due to wax accumulation as a result of prolonged shutdown. A pipeline restoration project was embarked on involving installation of pipe in pipe (PiP), which utilizes hot water circulation as pipeline heating element. Another complexity has been consistently supplying gas to the FPSO for fuel, which involves a cement packer and adding perforation jobs in gas wells. Additionally, the waxy crude in these fields requires gas lift to be produced, particularly after water production started to escalate. This gives an opportunity to introduce through tubing electrical submersible pump (TTESP) to the field, while reducing dependence on gas lift. Financial wise, cost optimization initiatives are necessary to maintain the operability of the fields. To date, five infill projects have been successfully completed, contributing to IOR by bouncing back PNPR oil production rate. Additionally, a gas cap blow down (GCBD) from NX J80 reservoir also managed to improve reservoir recovery factor (RF) while supplying additional gas for fuel. Meanwhile, the PiP system, an enabler for IOR, has successfully ensures smooth crude oil delivery above pour point temperature from PR Platform to FPSO. In terms of gas fuel supply forecast, proper gas wells production phasing is planned to secure steady supply until 2023. IOR through artificial lift, TTESP is planned to be executed soon in one idle production well with potential gain of 500 bopd, hence eliminating option to workover the well, which is costly. Viewing IOR from economic standpoint, operating expenditure (OPEX) reduction through new philosophies were implemented, including reduction of FPSO charting rate, proactive maintenance and low-cost chemical bull heading, resulting in better cash flow for PNPR. It is expected that existing PNPR wells can recover 2 MMstb of oil through extension of economic life via incoming infill drilling in 2021, translating into 1-2% increase from current RF. Moreover, PX and NX already produced ~80% more reserves than originally booked in the first FDP.

Offshore industry assets are capital intensive and downtime can have severe financial consequences. Additive manufacturing (AM) based supply chains can potentially offer offshore industry stakeholders a strong value and a competitive advantage, from lower costs and lead times to greater flexibility and agility. However, the current adoption level of AM for the offshore industry is very limited, despite the consensus that such technology could have potential applications for spare parts, repair and even new builds. While adoption of additive manufacturing could be a source of positive change, inadequate understanding of requirements regarding approval, qualification and certification processes required by regulatory authorities could hinder the progress of AM adoption in the offshore industry. Currently, there are only a handful of additive manufacturing standards available for early adopters of AM technology. Hence, costly and time-consuming nonstandard testing to ensure the integrity of the 3D printed parts is deterring the wider applications of additive manufacturing in the offshore sector, underscoring the need to develop optimal practice guidelines and standards from design to part build to operation. This paper aims to highlight several key challenges that hinder the adoption of AM in the offshore sector and to propose various solutions that can help to overcome these. Due to its novel approach, the risk-based certification pathway discussed in this paper will help the offshore industry and its supply chain ecosystem to build trust and confidence in the adoption of this emerging technology, which otherwise might not be possible.

Building a digital oil-field or digital twin, without involving multiple digital partners, and costly time-consuming digital endeavor is a significant challenge in Oil & Gas industry. In most cases, such systems are capable of data integration and visualization for only a part of an oil-field. Real-time analytics is missing to transform the digitalization into a smart and scalable system. The objective of this paper is to present a digital oil-field creator driven by a computational framework to perform key analytics for oil-field life cycles. A computational framework, networked with decentralized analytics engines that are equipped with a predictive analytics computation system, and an automated design engineering system has been developed. The predictive analytics computation system performs engineering design using data, pipeline integrity, platform structures, and coupled systems integrity and equipment integrity. The automated design engineering engine performs conceptual and FEED for subsea elements such as pipelines. These computational engines are then integrated into a self-service 3D digital twin creator for the user to operate on the front end and to receive analytical insights. 3D digital twin creator is capable of creating oil-field architecture within a fraction of the time utilizing the traditional model. Additionally, the creator optimizes the subsea architecture based on a selected set of criteria including CAPEX or OPEX costs. The system then performs conceptual or FEED level engineering including finite element analysis (FEA) using automated engineering saving as much as 80% of engineering time. Finally, the digital model is able to conduct asset integrity predictive analytics using machine learning from the monitored data. A Gulf of Mexico (GOM) oil field concept architecture was created by the digital twin creator and the computational framework. The system performed an automated pipeline conceptual optimization, buckling and free span design, and finally conducted riser integrity and equipment integrity. The computational framework is flexible and scalable to incorporate any organization's existing engineering process. The multidisciplinary complex analytics systems are networked in a way to maximize the integration of multiple oil-field systems from multiple companies and their asset's operational status in a 3D visual without a complex or expensive digital system. This digital system not only integrates multiple phases of the oil-field life cycle but also allows the reuse of all processes across different projects and time.

The characteristics of a primary well pattern in offshore oilfields are: large well control reserves, large well spacing, thin well pattern, multi-layer combined production and develop highest quality reserves. Infilling adjustment project is of great significance for field life extension, full utilization of facilities, efficient production, remaining oil tapping, well pattern improvement, water flooding optimization, reservoir pressure maintains and production stabilization for offshore This paper takes an oil field in Bohai as an example to analyze the potential and risks of the infilling 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.

The BC10 block encompasses multiple deepwater fields offshore Brazil and is tied-back to the FPSO ´Espirito Santo´. Since achieving first oil in 2009, the production was expanded through the Phase 2 and Phase 3 subsea tie-backs, having by early 2019 a total of 29 wells connected to the system. BC10 is a joint venture among Shell (operator), ONGC and Qatar Petroleum. As part of the strategy of "filling the hub", the development team matured infill well opportunities, which materialized in New Oil throughout 2019. The delivery of this additional production was enabled by the deployment of various new technologies, which supported the accelerated schedule and low-cost mindset of the project. Most notable is the deployment of the Compact Manifold and jumpers with flexible lines integrated to the horizontal connectors. In parallel to new wells, the Subsea team worked on a system debottlenecking that enabled the production of additional 2,000 bpd by routing selected fields to dedicated subsea pumps, instead of commingling low- and high-pressure systems into same inlet pressure pumps. This was enabled by installation of an electrical actuator that automated control of a formally manual valve at low CAPEX. Looking forward, the BC10 Infills Project team is planning for Q1 2020 the installation of the next-generation of Xmas Trees. This Xmas Tree is significantly lighter and cheaper than the previous company standards Enhanced Vertical Deepwater Tree(EVDT). It required significant qualification effort from R&D to ensure all new components delivered as part of this new generation of XT are reliable and satisfy the systems functional requirements. The qualification is completed, it has been confirmed that the well OS2 will carry the first new technology Xmas Tree in 2020.

The pre-drilling campaign for the Johan Sverdrup development was a key contributor to the successful execution of the first phase of the mega-project. The initial pre-drilling plan consisted of drilling six (6) oil producers, seven (7) subsea injectors and one (1) pilot target. At the end of the campaign, however, as many as eight (8) oil producers, twelve (12) subsea injectors and six (6) pilot targets had been drilled, more than one year ahead of the original schedule and NOK 7 billion (nearly 800 million USD) below budget. All the wells in the pre-drilling campaign were drilled by the semi-submersible drilling unit Deepsea Atlantic (Odfjell Drilling) and the objectives were met on all wells. After a summary of the results of the campaign, the focus of this paper is to identify some of the key success factors behind the campaign and attempts to draw lessons-learned of relevance to future drilling campaigns. Key areas to be assessed in the paper include: contract strategies including the use of integrated service and rig contracts with common incentives to develop and maintain a "One-Team" mentality; the further development of the ‘perfect well’ approach and Lean methodology to minimize waste and maximize efficiency of the campaign; as well as efforts and arenas to systematically promote collaboration, openness and regular experience transfer among the different parties involved (operator and contractors). Since the pre-drilling campaign was completed, the Johan Sverdrup project has successfully tied back, completed and started production of the eight (8) pre-drilled oil producers and injection in the twelve (12) subsea injectors.

It is a sobering statistic that 68 of 76 proposed major offshore developments were cancelled in 2015. There has been gradual improvement since then with system cost reductions and the oil price recovery, but nonetheless prospects that could be very profitable with the right development concept have been rendered uneconomic by overblown cost estimates. Conversely prospects with poor economics may go ahead due to overestimated production expectations. Production forecasts are generated by reservoir models. These models are often first constructed early in the development process, and refined multiple times as the process progresses and more information becomes available, e.g., from appraisal wells and production history. Meantime, production system design and sizing are often performed by different groups in the E&P company or by subcontractors in virtual isolation from each other. Updates from the reservoir modelling are not necessarily shared between these groups resulting in disconnects that can impact project viability and economics. Better collaboration between these groups and use of integrated reservoir and production system models address and sometimes resolve these issues. However, even in cases where integrated models are used, rather than harnessing the full power of the reservoir model, it is often dumbed down. This is done primarily in an attempt to save time, but it results in poorer representation of the actual reservoir response, e.g. losing the effect of well interference and failing to capture the pressure distribution and pressure changes with time in the reservoir. In this paper some real examples are provided of disconnects and lack of modelling fidelity with the potential for severe consequences on project economic performance. The four examples that will be discussed in this paper are as follows: Over-simplification of the reservoir representation for a gas field led to a proposed high- capacity subsea compression system being uneconomical. Reevaluating with a full reservoir model showed the compression system was over-sized and would underperform. Correcting these issues transformed the project economics and enabled the project to progress towards the FID. A simplified representation of the reservoir for a tieback resulted in insufficient natural production (no artificial lift) to be economic and insufficient production increase to justify subsea pumping. However, when reevaluated with more detail, the project became economical using a pumping concept. Passing a simplified production forecast from the reservoir team to the flow assurance team for a long tieback development resulted in overlooking the most onerous period of production for thermal management. If this oversight had made its way into the final design of flowline insulation, the tieback may well have plugged with wax deposits within a few years of operation. Use of complete forecasts within an integrated simulation framework prevents this kind of issue. Use of an inappropriate simplifying assumption while evaluating a brownfield redevelopment resulted in an overestimated production potential of the proposed new wells. When the error was corrected, an additional iteration of the development concept to downsize it was required which delayed first oil. Integrated reservoir and production system modelling avoid these kinds of planning and investment mistakes happening in the first place. This paper challenges the notion that detailed, integrated simulation is not required until later stages (FEED, execution) of a field development project, if at all. The presented examples are based on actual project experience. They provide quantitative evidence that integrated simulations have avoided costly development concept iterations and even more costly mistakes. Sometimes this allowed assets with marginal economics to be reconsidered for the operators’ project execution pipeline. Sometimes it resulted in the need to revisit economic analysis and development concepts due to initial overestimation of well performance.

In light of the deep industry downturn that started in 2014, there was a drastic reduction in the number of deepwater projects being sanctioned. Among the few projects that were sanctioned, many of them were tie-backs or smaller production facilities that potentially can be built out in phases. There are both pros and cons related to this trend of more phased and smaller developments and the purpose of this paper is to highlight these differences. We identify five pros and five cons. The pros are relatively intuitive, e.g. they lower the initial capex, payback period and overall project risk as you are committing fewer resources into the development project. On the other hand, the potential cons are less explicit and typically only visible longer term, including potentially lowering the long-term value creation, limiting the flexibility for future upside projects through e.g. increased/enhanced oil recovery (IOR/EOR) initiatives or tie-backs. By performing some sensitivities, it is possible to give examples where operators may miss some value creation by choosing phased and/or scaled down development solutions. We have looked at three project examples; Buckskin in the US Gulf of Mexico (GoM), Johan Castberg in the Norwegian Barents Sea and Liza offshore Guyana. For these three examples, the results of the sensitivity analysis suggest that overall value creation could have been increased 4-12% if the operators had chosen concepts with higher capacity. However, this increase is contingent on achiveving 20% savings on the capital expenditure (capex per boe) compared to the original concept. Additionally, these enlarged concepts would have created more risks, but from a subsurface and project execution point of view. As such, the pros may outweigh the cons of choosing a more phased and/or scaled down concepts for these examples. Nevertheless, it is important that the industry makes the proper assessments, including longer-term benefits, before making final investment decisions and not overlook potential value creation opportunities.

Despite increasing demand for cleaner energy around the world, oil is still the main global energy source and this scenario will not change in the short term. Together with natural gas, they supply 57% of world primary energy demand ( BP, 2018 ). Therefore, if a country wants to benefit from having its hydrocarbon reserves developed to generate wealth, it is crucial to enable economic conditions for such. This study aims to show the impact that distinct fiscal systems adopted by each country can have on the valuation of an oil field and its commercial feasibility, from an international oil company perspective. Fiscal terms define, among other things, how revenue from oil production is shared between operators and the host country. To investigate such topic, a deepwater offshore oil development project was valuated using discounted cash flow method. Sixteen scenarios were created, considering a combination of four distinct field sizes under four fiscal systems, selected from some of the world's top oil producing countries. For each scenario, internal rate of return (IRR), which indicates the project's economic return for the operator, and government take (GT), which indicates how much of the oil revenue is directed for the host country, were calculated. Findings show very distinct results in each scenario, with IRR for operators ranging between 8 and 21% and government take between 57% and 84%. Considering that project returns should always be higher than a company's capital cost, in some scenarios the discovery would not be declared commercial. Results also show that, in general, large oil development projects in countries with tax/royalty system present a higher return for the operators, while production-sharing contracts tend to generate a higher government take. This shows that the same oil field, under same geological conditions, can offer very different economic returns to the operators and host governments, depending on the fiscal system in place. In some cases, the fiscal system has such an impact on the economic feasibility of the project, that it may even prevent the discovery to be declared as commercial and, therefore, not be developed and booked as proven reserves. The main takeaway of this study is that understanding fiscal systems is an essential tool for operators to properly evaluate its projects and one of the most important features governments can adjust to attract private investment to their oil industries.

Field development complexity in today's subsea industry is ever increasing; prospects tend to be smaller while located in deeper waters with deeper well targets, located farther from shore, and in colder regions. As a result, sanctioning projects in the current oil price environment is challenging and adopting efficient field development planning (FDP) processes is critical for project viability. This paper describes a fast-track, collaborative field development process to address these needs. This fast-track field development process has been used with great success on numerous projects worldwide. The paper describes how the process integrates layout development and equipment selection with a fully integrated, holistic fluid flow simulation and establishes an excellent collaboration platform for the development team, fully enabling close interaction between teams that traditionally would not work closely together. The paper demonstrates how experience gathered to date has clearly shown how the fully integrated approach to field development is crucial for the optimal development of the concept and how the result provides the highest return on investment. Subsea production system and subsea umbilical, riser, and flowline specialists now work closely together with reservoir, production, and drilling engineers, ensuring the development of optimal solutions earlier in the FDP process and simultaneously enabling the teams to overcome the challenges that have previously been imposed by the segregation of different technical disciplines. The paper shows how key features of this process enable ultra-rapid scenario generation—a much shorter time from initial layout development to life-of-field production profiles—and how the process can be used to maximize overall economic performance for the project.

Performing robust economic valuation is critical to ensure success on oil development projects. In a dynamic market with ever changing variables, risks and uncertainties must be well analyzed and mitigated to prevent less than expected economic returns in mega-projects such as an offshore deep-water oil field development. This study aims to evaluate what are the most important factors that should be considered when assessing risks in a project economic valuation, using Brazil’s Production Sharing Contract (PSC) fiscal system as an example. A sensitivity analysis was performed in a standard offshore oil production project using the discounted cash flow method. First, a base scenario was calculated, and then, four key assumptions were chosen to be tested – oil prices, capital expenses (capex), operational expenses (opex) and recoverable reserves - and changes of + and - 20% in each, one at a time, were applied to the base scenario, and their impact on the internal rate of return and government take were measured. Findings indicate that, at least in the Brazilian PSC case, oil price is the most influential parameter in the project profitability, presenting an almost perfect positive correlation with the rate of return. Oil price is also the most difficult assumption to project and the one that is completely out of companies’ control, which poses them a significant challenge, to be able to keep its projects economical under volatile prices. Main investment decision gates happen years before first oil is produced, so the level of uncertainty on this parameter is very high. This study reinforces the concept that a good oil price forecast is paramount in projects valuation. Additionally, companies should always make investment decisions based on multiple oil price scenarios to determine the project’s financial risk.

Field development is a complicated process involving a multitude of disciplines, technologies and workflows. The typical approach to field development is long, fragmented and costly. This is due to set process and work flows with limited flexibility, inefficient tools and transfer of information, uncertainty of required scope for each phase and the management of multiple contractors. An example of this is a stage gate process, where regardless of the size of the prospect the same set work tasks and deliverables are required to pass to the next phase, generally no assurance is performed upfront to determine the actual requirements. Another example is field development tools, which are used in isolation from reservoir simulation to flow assurance/facilities design with limited integration, which leads to the inefficient transfer of data and a reduction in accuracy. The above causes unnecessarily long schedules, repetition in scope and results in sub-optimal technical solution and project economics. The requirement to transfer and interpret information between multiple parties and stages (internal and external) creates unnecessary complexity and introduces additional risk to the final technical solution. This paper will demonstrate the value of an Integrated Field Development approach for a large Deepwater gas condensate development offshore Australia, and how this approach can dramatically reduce duration, improve accuracy, lower contingency and maximize the economics of a project. It shows the clear advantages of facilities engineers working closely with subsurface, drilling and completions and will highlight some of the key features that make the Integrated Field Development approach a success.

Having a resilient break-even price is essential for deep-water development projects due to all the technical uncertainties inherent to the O&G business and, because of the oil price volatility, especially in recent times. To cope with this permanent threat, the Libra Consortium envisaged, structured and implemented a consortium corporate program called Libra@35. The programs’ main objective is to reduce the projects break-even prices to US$ 35/bbl, by improving the recovery factor and /or reducing costs. This paper describes the Libra@35 methodology and procedures, explaining how the program has helped Libra optimize its projects on a continuous basis through a structured and rigorous methodology. Additionally, it presents the beneficial results and impacts achieved to date. To finalize, the paper discloses the Consortium's future objectives for this successful Program and how it is structured to assist in shaping Libra's projects of tomorrow.