A major challenge in offshore development is to ensure unimpeded flow of hydrocarbons. Managing solids such as hydrates is the key to the viability of developing a deepwater prospect. Common methods to prevent and reduce hydrate risks are generally based on injection of thermodynamic inhibitors to prevent hydrate formation or use of kinetic hydrate inhibitors to sufficiently delay hydrate nucleation/growth. Currently, the amount of inhibitor required is either calculated and/or determined based on lab experiments. The amount of inhibitor depends on various parameters, including, water cut, inhibitor loss to hydrocarbon phases, aqueous and non-aqueous fluid compositions, operating conditions. Generally a safety factor is considered and the resulting inhibitor is injected upstream without much downstream measurements. Despite the usual safety margins, gas hydrates are formed which could result in serious operational and safety concerns. This is mainly due to changes in the system conditions (e.g., rates and water cut) and/or malfunction of one of the equipment. In most cases, the amount of inhibitor is more than what is necessary and is not adjusted with seasonal changes, affecting CAPEX/OPEX. As a result of a joint industry project several novel techniques, based on downstream and online measurements have been developed, for: 1. Monitoring the hydrate safety margin to optimise inhibitor injection rates. The system determines the amount of inhibitor in the aqueous phase and the degree of inhibition they can offer. 2. Detecting the initial hydrate formation, as an early warning system against hydrate blockage. The system detects the changes in the system due to hydrate formation with the aim of giving the operator enough time to prevent a blockage. The main advantages of the above techniques are minimising the amount of inhibitor required and preventing pipeline blockages due to hydrates, hence the cost of inhibitor, impact on the environment, cost of remedial actions and deferred production. A number of techniques have been investigated during this project with some techniques selected for prototype development. The developed prototypes have been tested. In this presentation, an update on the latest results of this new approach in flow assurance control is presented.

The expanding demand for primary energy has pushed exploration and production activities towards more challenging environments, such as the north slope of Alaska, Siberia and deeper oceans. In many cases associated gas could be a limiting factor in the field developments. While stabilised oil could be transported by pipelines and/or tankers, the options for gas and associated gas is rather limited and/or not economical. There are strict limitations on flaring due to environmental/economical concerns, and most of the available options for gas utilisation (e.g. gas to liquid, gas to wire, compressed natural gas…) require considerable CAPEX. Recently, we have proposed HYDRAFLOW, which is a Cold Flow solution for avoiding gas hydrate problems. This could provide a solution for gas transportation. The concept of HYDRAFLOW is based on allowing/encouraging gas hydrate formation, but preventing their agglomeration and pipeline blockage by using chemicals and/or mechanical means. The aim is to eliminate/minimise the gas phase by converting it into hydrates and dispersing hydrates in oil and/or aqueous phase. Water could be added to maximise gas conversion into hydrates and/or adjusting the slurry viscosity. Furthermore, a loop concept has been developed where part of the liquid phase could be recycled, minimising chemical discharge to the environment. As HYDRAFLOW basically converts gas into hydrates and transport it as slurry in a liquid phase, it could provide a solution for gas utilisation for fields where the ambient temperature and pipeline pressure are inside the hydrate stability zone. In this communication, after introducing the HYDRAFLOW concept, the latest results of laboratory tests at subzero conditions are presented as well as an economical evaluation and a pipeline transportation simulation on one of the West Siberian oil fields. These simulations demonstrate that the concept is viable, and suggest that HYDRAFLOW technology could offer significant benefits over existing flow assurance strategies, providing a novel low CAPEX/OPEX solution for gas utilisation. Introduction The rising trend in global energy demand and high price of the oil has led to production from reserves previously considered uneconomic and/or less practical. There are many challenges in production from these reserves due to various reasons such as:–The field is remote and/or located in deepwater (e.g. stranded gas).–The gas field is too small to justify a gas pipeline for long-term production (marginal)–Ambient temperatures are very low such as the north slope of Alaska, Siberia and deeper oceans.–There are restrictions on flaring associated gas. In many cases associated gas could be the limiting factor in the field developments. While stabilised oil could be transferred by pipeline and/or tankers, the options for gas and associated gas are rather limited and/or uneconomic. Worldwide, governments are restricting/limiting flaring associated gas. In many cases these restrictions could limit oil production rates. According to statistics [1], approximately 113 billion m3 (4 trillion cubic feet) of natural gas is being flared annually and close to 142 trillion m3 (5,000 trillion cubic feet) of natural gas (either associated with crude oil, or non-associated) is stranded worldwide. However, there is a high demand for natural gas in global market and considerable effort is being made throughout the industry to reduce the costs for natural gas transportation. There are a number of methods of exporting gas energy from an isolated field for use elsewhere such as pipelines, liquefied natural gas (LNG), gas to liquid (GtL), Gas to commodity (GtC), gas to wire (GtW), compressed natural gas (CNG) and gas to solids (GtS), i.e. hydrate (NGH).

The Dunbar Field (UKCS, Block 3/14a), operated by Total E&P UK, is situated on an intermediate terrace between the East Shetland Platform and the Viking Graben and characterised by a series of pre-Cretaceous and structurally aligned tilted fault blocks. The principal hydrocarbon accumulations are contained in the Middle Jurassic Brent Group and younger Upper Jurassic Heather Sands. Internally, the field is compartmentalised by a number of N-S faults and a secondary alignment of NE-SW faults which cross cut and often offset the main N-S faults. The larger scale faults down throw to the east and subdivide the field into four main areas; the West Flank, Central Panel and Frontal Panel with an uplifted Horst (Triassic) Panel in the south. Each of these panels has specific reservoir and fluid characteristics. The Central and Frontal panels have a substantial production history of 15 years. The field is in steep decline with high water cut in water flooded areas, and extremely low pressure in compartments produced by natural depletion. A better understanding of recovery from the main flow units is essential for estimation of drainage volume, optimisation of water injection pattern and infill well placement/completion. The ability to better define the size of the connected volumes through improved fault identification (Seismic PSDM3D Reprocessing) along with an improved understanding of the permeability field (sedimentological, petrographic, XRD, SEM, SrRSA, DST analysis & simulation studies) has been key in assessing Dunbar’s future potential. An intensive data acquisition campaign has been integrated in a comprehensive dynamic synthesis leading to a reservoir model history match that has improved our understanding of the field. This paper describes the multidisciplinary team work leading to an improved understanding of the recovery efficiency and reservoir connectivity leading to a further drilling campaign.

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