Over the last twenty or more years of reservoir performance prediction through simulation there have been only two fundamental changes. First was the evolutionary increase in computing speed that has allowed larger, more detailed reservoir models to be built. Second was the revolutionary change in approach that involved the entire subsurface community in building integrated reservoir descriptions. The next big change may in time prove to be BP's Top-Down Reservoir Modelling (TDRM). This is a new pragmatic approach to fully incorporate reservoir uncertainty in model construction and performance prediction. TDRM is proprietary technology that has been developed in BP through extensive R&D, and consists of a philosophy and tools that enable a faster and more robust exploration of uncertainty than has hitherto been possible. The philosophy is to start investigations with the simplest possible model and simulator appropriate to the business decision. Detail is added later as required. The approach overcomes the problems of the conventional "bottom-up" process, which uses detailed models that are too slow and cumbersome to fully explore uncertainty and identify critical issues. Highly detailed models cannot overcome an underlying absence of information, and can have the negative effect of creating a false sense of understanding. The TDRM tools have been designed to minimise manual iterations by creating a semi automated, flexible workflow for case management, assisted history matching, depletion planning optimisation and post-analysis. TDRM has been successfully applied to eighteen oil and gas reservoirs that range from development appraisal stage to mature fields, and has resulted in up to 20% increase in estimated net present value for the projects. Background The business imperatives in developing oil and gas reservoirs are faster pace and less risk from subsurface uncertainties. Quantification of the uncertainties is difficult and time consuming because of a) the intrinsic subsurface complexity, requiring integration of data from core to seismic scales (cm to 10's m), b) the sparseness of information requiring estimation of unknown data for the construction of possible geological and simulation models, and c) the need to consider a large number of development scenarios. Processes used to estimate uncertainties vary, but the general trend is to start by building a large (multi-million cell) geological model. Often the type of model is independent of the business decision, timeframe and amount of data available. Due to the complex workflow and effort, the focus is on building only one, the "most likely", detailed model, even though evidence from the data indicates that there are many possible models. The next step is to build a simulation model that typically involves upscaling the geological model. If production data exist, this simulation model is history matched manually. Iterative rebuilding of the underpinning geological model is generally avoided. Exploration of the uncertainty in performance prediction using the simulation model is often limited to one-at-a-time sensitivities around a base case. These sensitivities are only a small sample from the factorially combined possibilities. The effort to reach this stage is significant and can be many months for a major reservoir decision. Overall, the focus of activity has been building ever more complex (hence apparently realistic) models and predicting performance from only a single realisation. Breaking away from this general approach and focusing on the real uncertainty breadth in performance prediction is a conceptual leap which requires new technology and understanding. Technology Improvements Technology improvements are providing better information about current and future reservoir performance and offer the opportunity to quantify the risk from subsurface uncertainties. Some of these advances are highlighted below.

Summary. Horizontal wells have been shown to increase productivity, to reduce coning tendencies, and to improve recovery. Given the potential applications in the Prudhoe Bay field, a project was initiated in 1984 to evaluate benefits and to drill and test three trial wells. This paper reviews production and reservoir engineering aspects of the trial program. It includes the objectives of the test program, the planning and drilling of three wells, the forecasting of production rates and recoveries, and the testing and analysis of actual well performance. In summary, the three wells have been successfully drilled and completed, with each well costing less than its predecessor. The wells have exhibited productivities two to four times that of conventional comparison wells, and increased oil recovery is anticipated. Horizontal wells can improve production rates and recoveries by a variety of mechanisms. At their most basic, the long wellbores allow longer completed intervals and therefore increased production rates. In reservoirs overlying an aquifer or located under a gas cap, the increased standoff from the fluid contacts can improve the production rates without causing coning. Additionally, the longer wellbore length serves to reduce the drawdown for a given production rate and thus further reduces coning tendencies. Fractured reservoirs can also benefit from horizontal wells. Long wellbores are likely to intersect more fractures and hence improve both production rate and ultimate recovery. Furthermore, the application of horizontal wells early in a project may allow development with fewer wells because of the larger drainage area of each well. In some fields, the advantages of horizontal drilling may allow development where conventional techniques would be uneconomical. The development of the Prudhoe Bay oil field, on the North Slope of Alaska, has been extensively reviewed in published literature. For reference, a field outline showing waterflood and non-waterflood area (Fig. 1) and a gamma ray log section depicting the various zones (Fig. 2) are included. Two areas of the field offer some of the potential advantages of horizontal drilling previously outlined.1. The midfield area generally contains a thick remaining oil column overlain by an expanding gas cap. Because Prudhoe Bay production will become constrained in the near future by the ability to compress and to reinject produced gas, rather than by oil productivity, immediate field production rate increases will result from reducing gas coning.2. The extreme downstructure part of the Prudhoe reservoir is undeveloped. The thin oil column and potential problems caused by water coning from the underlying aquifer have made development relatively unattractive to date. Horizontal wells offer the possibility of reduced coning and increased production rates, perhaps increasing the attractiveness of development. Projected remaining oil at abandonment for the entire field is about 12 billion STB [1.91 × 109 stock-tank m3], a significant target for any improved recovery scheme such as horizontal drilling. Given this potential target, well locations were screened for application as horizontal wells. A three-well program was selected to address both target areas and to develop a broad experience base. The selected well locations are shown in Fig. 3 and are discussed here. First Well Location (JX-2). This 80-acre [32-ha] infill location is in a structurally simple part of the field. Stepout from the gravel pad (from which all Prudhoe Bay wells are drilled) is less than 5,000 ft [1524 m], allowing a reasonable directional profile to the larger depth at 8,915 ft [2717 m]. The well is located at the base of the oil column to maximize standoff from the gas cap. Drilling technology and drainage area considerations limited the design completion length to 1,500 ft [457 m]. Second Well Location (B-30). The second midfield horizontal well was not spudded until after the initial well was tested. This second well increased drilling experience before the more difficult drilling associated with the Y-20 location. This experience factor and the additional reservoir performance data justified two horizontal wells in the midfield area. Third Well Location (Y-20). Y-20 was recommended as the third horizontal well and the first in the peripheral area. This would be an extended-reach well completed at the top of the reservoir to maximize standoff from the aquifer. The thin oil column in the periphery and longer stepout made this a more difficult, higher-risk well to drill. The stepout to the beginning of the horizontal section was approximately 8,300 ft [2530 m]. This exceeded the 5,000-ft [1524-m] stepout restriction placed on the first well. Information from the first two wells, however, was designed to permit a stepout of this magnitude. Because of the increased stepout, design length for this completion was limited to 1,000 ft [305 m]. Evaluation of Benefits Empirical, analytic, and numerical simulation methods were used to forecast the benefits of the horizontal wells planned for Prudhoe Bay. The benefits considered are productivity, critical coning rates, and recovery. Productivity. The productivity of a conventional well is proportional to the permeability-thickness product. Low productivities result from low values of permeability or formation thickness (or both). This can be compensated for in horizontal wells where the length of the horizontal section is not imposed by nature but chosen. The permeability-length product in horizontal wells plays a role similar to that of the permeability-thickness product of conventional wells. P. 1417^

Waterflood residual oil saturation, in mixed wettability reservoirs, is often a strong function of pore volumes (PV) injected. The Endicott Field, Alaska displays typical mixed wettability behavior with coreflood remaining oil saturation varying from 40% at 1 PV to 12% at infinite PVs. Although only about 1 PV will be injected in the reservoir, surface film drainage may act to reduce oil saturation making determination of the correct effective residual oil saturation difficult.Accurate determination of waterflood residual oil saturation is essential for assessment of waterflood performance and evaluation of enhanced recovery processes. To minimize uncertainty in predicting effective residual oil saturation in mixed wettability reservoirs it is necessary to consider the competing effects of relative permeability, graVity forces, and imbibition capillary pressure. A mechanistic simulation approach is presented for scaling up laboratory results, that considers all active forces.References and Illustrations at end of paper.

Cases studies from three North Sea turbidite reservoirs will be presented, which together demonstrate our current understanding of permeability and relative permeability upscaling. The three formations, the Magnus, Magnus Sand Member (MSM), the Magnus, Lower Kimmeridge Clay Formation (LKCF), and the Andrew reservoir each provide distinct challenges for reservoir modelling, either because of reservoir complexity, the fluids in place, or the phase of field life. To meet these challenges, several novel upscaling approaches have been developed. Their use will be explored and current best practice delineated. This best practice differs significantly from previous definitions of "effective permeability" by placing more emphasis on extracting multiple properties from the fine scale geologic models. Distinct upscaling calculations are required to assessthe quality of sands,the quality of barriers, andthe tortuosity of flow around these barriers. Similarly, when constructing upscaled relative permeabilities, the "effective" curves are distinguished from the "pseudo" curves. The former describe the physical displacement of fluids, while the latter include the additional numerical dispersion corrections required when implementing the relative permeability functions within a coarsely gridded full field simulator. P. 133

The global acceptance of the 2030 Agenda for Sustainable Development marked a new era in global development. Natural resources are essential for the attainment of most of the Sustainable Development Goals (SDGs). Why, how, when and where they are discovered, produced, consumed, recovered and re-consumed will define more than any other actions whether we have succeeded and created value. In response, the United Nations Framework Classification for Resources (UNFC) is transforming into a comprehensive and integrated system that can be used for managing these resources in concert to ensure balanced, responsible and resilient development. UNFC applies to projects in energy, including oil and gas, renewable energy, nuclear fuel resources; minerals; geological storage; and anthropogenic resources. Groundwater will be the next focus. The UNECE Expert Group on Resource Classification, including inter alia the SPE Oil and Gas Reserves Committee and Committee for Mineral Reserves International Reporting Standards have aligned the Petroleum Resources Management System (PRMS), the Committee for Mineral Reserves International Reporting Standards (CRIRSCO) family of codes for solid minerals and the Oil and Fuel Gas Reserves and Resources Classification of the Russian Federation. Alignment to other national systems such as the Chinese petroleum and mineral systems are under development. The Nordic countries (Finland, Norway and Sweden) have developed independent UNFC guidelines for mineral resources. The African Minerals Development Centre has decided to establish a continent-wide system for the management of Africa's oil, gas, mineral and renewable energy endowments, grounded in UNFC but tailored to meet local needs, priorities and circumstances. The Coordinating Committee for Geoscience Programmes in East and Southeast Asia (CCOP): has decided to develop guidelines for adoption of UNFC as the unifying framework in 14 member countries. UNFC, in its transformation, has incorporated guidelines for social and environmental considerations. These guidelines provide the critical social and environmental basis for classification of resource projects in a manner that allows environmental, social and economic aspects to be in equilibrium. UNFC facilitates transformative resource management for sustainable development recognizing the SDGs as the very core of this development. UNFC is a tool for policymaking, government resource management, business process innovation and financial management and reporting. Key stakeholders such as governments and companies can build a new narrative for the resource industry by using UNFC in day-to-day management functions. UNFC is a compass to use when navigating the complex landscape of natural endowments, social, economic and sustainability issues to find efficient and effective paths between often competing and sometimes mutually exclusive needs. This paper presents the recent expansion of the UNFC guidance to cover social and environmental impacts as well as the further transformation of the system that is underway to make it a valuable tool in resource management for governments and businesses.