This paper presents our progress in developing, testing, and implementing a Ubiquitous Sensing Network (USN) for real-time monitoring of methane emissions. This newsensor technology supports environmental management of industrial sites through a decision support system. Upon detection of specific inputs, data is processed before passing it on for appropriate actions (Data→Insight→Actions) . The technology integrates wireless methane sensor nodes, weather sensors, edge-based devices and is powered by a self- contained solar-battery powered system. A cloud-based data analytics IoT solution is included for handling continuous sensor monitoring. A sample of results from an in-house simulated well site are presented within the body of this paper. Preliminary predictions seem to correlate well with the true emission rate as indicated by the proximity of the predictions to the forty-five-degree line. Running more tests should allow us to further estimate the error distribution as well as the prediction interval width and the overall emission rate prediction trend. The initial results demonstrate that the developed technology can quantify the emission rate (scfh) within 1% and 45% error, and a localization error within six feet to fifty feet given a test area of 10,000 square feet. This integrated solution is being ruggedized and the analytics are being optimized for continuous monitoring of methane emissions at customer sites for safety, product loss prevention, and regulatory compliance.

Crosslinked polymer gels have been widely used to overcome water and gas coning problem in the petroleum industry. Recently, nanoparticles are identified to have a potential of reinforcing the polymer gel systems by improving physical bonding and heat transfer properties in the gel structure. In this study, silicon dioxide and aluminium oxide nanoparticles were introduced to xanthan gum polymers that were crosslinked by chromium (III) acetate, to create polymeric nanocomposite gels with higher shear strengths. The gelation time and gel strength have been selected as main parameters to evaluate the effect of nanoparticle types and concentrations on the nanocomposite gels performance. The gelation time is measured until the onset of gelation or the moment when apparent viscosity starts to increase at 60°C. The gel strength is represented by the storage modulus (G’) after 24 hours of gelation at 60°C. Both parameters were measured by a rheometer, through constant shear rate and oscillatory tests respectively. The addition of 1000 and 10000 ppm of silicon dioxide (SiO 2 ) nanoparticles into a solution of 6000 ppm xanthan gum polymers that are crosslinked with 50000 ppm chromium (III) acetate caused insignificant changes in gelation time. Similar result was also reported when 1000 and 10000 ppm of aluminium oxide (Al 2 O 3 ) nanoparticles was introduced into the polymer system. This suggests that when SiO 2 and Al 2 O 3 nanoparticles are introduced to xanthan/chromium (III) Acetate system for field application, no additives would be required to prolong or shorten gelation time to counter the nanoparticles addition. To analyse the gel strengths, the results from the oscillatory test were averaged throughout the frequency range, and it was shown that the addition of SiO 2 nanoparticles decreases the average storage modulus from 75.1 Pa without nanoparticles, to 72.3 Pa at the nanoparticles concentration of 1000 ppm. However, the average storage modulus increased to 83.0 Pa and 94.7 Pa at higher nanoparticles SiO 2 concentrations of 5000 ppm and 10000 ppm. The same trend was observed for the nanocomposite gels that were produced by Al 2 O 3 nanoparticles. Similarly, the storage modulus decreased initially to 70.8 Pa at the concentration of 1000 ppm, then it increased to 89.9 Pa and 109.4 Pa at nanoparticles concentrations of 5000 pm and 10000 ppm, respectively. Hence, the nanoparticle-enhanced biopolymer gels showed insignificant changes of gelation time, and at the same time, they demonstrated up to 45% improvements in the gel strength properties when the nanoparticles concentration is higher than 5000 ppm. In conclusion, the nanocomposite gels demonstrated reinforced bonding properties and showed higher gel strengths that can make them good candidates for leakage prevention from gas wells and blocking of water encroachments from aquifers into the wells.

Reservoir management for an economically successful chemical EOR project involves maintaining high injectivity to improve processing rates. In the Captain Field, horizontal injection wells offshore have been stimulated with surfactant-polymer fluids to reduce surrounding oil saturations and boost water relative permeability. The surfactant-polymer stimulation process described herein enables a step change in injectivity and advances the commercialization of this application. This paper explains the damage mechanism, laboratory chemical design, quality control through offshore field execution and data quantifying the results. Phase behaviour laboratory experiments and analytical injectivity models are used to design a near wellbore clean-up and relative permeability improvement. Three field trials were conducted in wells that had observed significant injectivity decline over 1-3 years of polymer injection. Surfactant and polymer are blended with injection water and fluid quality is confirmed at the wellheads. Pressure is continuously monitored with injectivity index to determine the chemical efficiency and treatment longevity. Oil saturation changes and outflow profile distributions are analysed from well logs run before and after stimulating. Learnings are applied to refine the process for future well treatments. The key execution elements include using polymer to provide adequate mobility control at high relative permeability and ensure contact along the entire wellbore. Repeatability of success with surfactant-polymer injection is demonstrated with decreased skin in all the wells. The key results include the oil saturation logs that prove the reduction of oil near the well completion and improves the relative permeability to aqueous phase. The results also prove to be sustainable over months of post-stimulation operation data with high injectivity. Injectivity enhancement was supported by chemical quality control through the whole process. From laboratory to the field (from core flood experiments to dissolution of trapped oil near wellbore), surveillance measurements prove that the chemical design was maintained and executed successfully. The enhanced injectivity during clean-up allows for higher processing rate during polymer injection and negates the need for additional wells. The application of surfactant-polymer technology can rejuvenate existing wells and avoid high costs associated with redrilling offshore wells. This improves processing rate for EOR methods and can even be applied to waterflood wells to improve the injectivity, e.g low permeability reservoirs.

Significant advancements in physics-based model development, software workflow practices, multi-core processing and cost-effective cloud computing has enabled the adoption of high fidelity, three-dimensional (3D) modeling such as computational fluid dynamics (CFD), finite element analysis (FEA), and other first principles-based analyses into normal engineering design practices. Historically, integration of these tools into the standard engineering workflow was challenging due to the excessively long turnaround times to deliver any results. Three Case Studies are subsequently presented where 3D modeling analysis was used early and seamlessly in the engineering design process to solve problems related to consequence analysis and equipment operational performance: Case 1) Risk assessment of pilot flame extinguishment due to inert gas discharge from the flare of an FPSO, Case 2) Jet dispersion analysis from HP/LP flare to assess hydrocarbon and H 2 S concentrations at critical locations on the platform, including results comparison between CFD results and a conventional dispersion tool – Flaresim, and, Case 3) Solving a fatigue induced cracking problem on the cooling water circuit of a heat exchanger using an integrated workflow consisting of CFD modelling of the cooling water, stress analysis using FEA, and structural integrity assessment per ASME BPVC VIII Division 2. The modelling results from these case studies were generated in timeframes similar to those using conventional engineering calculation methods, and thus allowed for prompt integration into the engineering design process without impacting project schedules and delivery. Moreover, the costs to perform these modelling analyses were not substantially greater than the costs associated with conventional calculation methods, thereby providing high value to the engineering projects.

Production, transportation and storage of highly waxy crude oil is very challenging. This is because they are usually characterised by high content of macro-crystalline waxes, predominantly consisting of n-alkanes (C 18 to C 36 ) that which could cause costly deposition within the wellbore and production equipment. The accumulation of deposited wax can decrease oil production rates, cause equipment breakdown, and clog the transport and storage facilities. Currently, different polymeric inhibitors have been utilised in the oil and gas field to mitigate and prevent wax deposition. However, as of today, there is no distinctive wax inhibitor that could work effectively for all oil fields. One of the objectives of this work is to study the efficacy of a blended commercial wax inhibitor - pour point depressant on wax deposition mitigation in a flow rig designed with 0 and 45-degree bends in the pipeline. Standard laboratory techniques using high-temperature gas chromatography (HTGC), rheometer rig, polarized microscope and elution chromatography were employed to obtain n-paraffin distribution, oil viscosity, WAT, pour point and SARA fractions. Series of experimentation were carried out with and without the inhibitor in a straight pipe test section. The severity of wax deposition in the pipeline built-in with a 45-degree bend is compared with a straight pipe. The blended inhibitor was tested at concentrations of 500, 1000, and 1500-ppm, under laminar and turbulent conditions. The crude oil sample was found to be naturally waxy with wax content of 19.75wt%, n-paraffin distributions ranges from C 15 -C 74 , WAT and pour point of 30°C and 25°C respectively. The severity of wax deposition in the test section is 43% higher in 45-degree bend compared to straight pipe. However, the severity of the deposition was reduced to 12.3% at extremely low temperature and flow rate. Nonetheless, better inhibition performance was achieved at 25 and 30°C. The wax thickness was reduced from δ wax ≈ 0.36mm at 5 l/min to δ wax ≈ 0.132mm at 7 l/min at constant coolant temperature (25 °C ) and 1500-ppm, whereas, no wax deposition was observed at 11 l/min. Mechanisms such as molecular diffusion due to frictional pressure losses, shear dispersion and gravity settling due to momentum change and hydrostatic, alongside with thermal difference are the main drivers for wax deposition in both straight and bend pipe. Whereas, the interaction mechanisms such as the nucleation, alongside with adsorption, co-crystallization, and solubilisation between the new blended inhibitor and the wax crystals provide an improved inhibition performance in the system even at extreme cases.

The Shetland Gas Plant (SGP) is a 500 MMSCFD capacity gas plant located at Sullom Voe on the Shetland Islands. It receives reservoir fluids, via twin 143km multiphase flowlines, directly from the Laggan-Tormore fields which are located 125km north-west of the Shetland Islands in approximately 600m water depth. Fluids arriving at the SGP are separated into gas and liquid phases. The gas is processed and then exported to St Fergus gas processing plant via the SIRGE and FUKA pipelines. The liquid phases are separated and the condensate is exported to the BP Sullom Voe facility for stabilisation and export by tanker. The aqueous phase (rich MEG) is regenerated at SGP to produce lean MEG for reinjection subsea, a by-product of the regeneration process is produced water. The produced water is then fed to the Effluent Water Treatment Plant (EWTP) for processing prior to being discharged to Yell Sound via a 3.75km pipeline. The effluent water treatment package was designed by SUEZ Eau Industrielle (patented design). The effluent water is required to meet strict discharge specifications as part of the operating consents, e.g. Biological Oxygen Demand (BOD), Chemical Oxygen Demand (COD), MEG, Benzene, Total Suspended Solids (TSS), etc. The Effluent Water Treatment Plant (EWTP) consists of 3 stages of treatment: physical, chemical and biological. The physical treatment contains; – A Corrugated Plate Interceptor, which uses gravity to separate the free oil from the produced water; – A Stripping Column, which removes BTEX (Benzene, Toluene, Ethylbenzene, Xylenes) and volatile hydrocarbons entrained in the water via transfer to fuel gas. The chemical treatment contains; – A Dissolved Air Flotation Treatment Unit, to remove any residual free oil and TSS utilising flocculants and coagulants. The biological treatment contains; – A Biological Aerated Flooded Filter (BAFF) Unit, which is an aerobic biological filtration process whereby a biomass (bacteria) give biological degradation of soluble organics while simultaneously removing suspended solids via filtration. The biological process removes the remaining MEG and BTEX and has the ability to handle varying loads of COD and BOD. The EWTP has been in operation since the start up of the SGP in February 2016. The paper will discuss: – The initial challenges faced during start up and the first year of operation and how these were overcome; – Current operation of the process including ongoing challenges and areas of success.

The Laggan & Tormore gas fields are situated some 125km north west of the Shetland Islands on the UK Continental Shelf, in approximately 600 metres water depth. The reservoir fluids are delivered directly from the subsea wells to the Shetland Gas Plant (SGP) through twin 18" diameter 143km flowlines. During the project phase of this development it became apparent that the site and support teams would require a method of monitoring and predicting flow assurance issues such as hydrate inhibition, slugging and liquid holdup, as well as optimising complex operations such as pigging and flowline depressurisation/repressurisation. The solution was the Pipeline Management System (PMS), a tool designed to predict the behaviour of fluids in the two 143km multiphase pipelines between the subsea systems and the arrival facilities at the SGP. The PMS combines LedaFlow, a dynamic multiphase flow simulator, with K-Spice, a dynamic process simulator. The Laggan-Tormore PMS was the first use of LedaFlow in an integrated simulator. The LedaFlow technology was developed by Total, ConocoPhillips and SINTEF over the last 15 years with Kongsberg joining the project in 2008 as a commercialisation partner. The model derives the multiphase hydrodynamic behaviour of oil, gas and water along a pipeline and approximates the behaviour in the radial directions via results from laboratory experiments and in depth knowledge of the physics of flow in a circular pipe. The PMS was developed by Kongsberg in conjunction with the Total E&P UK field operations team. It consists of an online, open-loop simulator, which allows the operations team to make decisions based on real time information of fluid behaviour in the flowlines, and an offline simulator, which allows what-if analyses to be carried out. The PMS has been in operation since Laggan-Tormore start up in February 2016. This paper will provide further details on the use of the LedaFlow technology and the operational aspects of the Laggan-Tormore PMS, giving an overview of the following: – The utilisation of the LedaFlow technology; – The various applications of both the online and offline modes of operation of the PMS and; – The benefits and challenges associated with the use of the PMS during its first year of operation.

The UKCS is set to decommission over 3,000km of pipeline by 2023. As Operators submit their plans to regulatory bodies they face spiraling costs in order to make safe the industry's complex subsea infrastructure, estimated to represent 7% of the overall cost of field decommissioning. In order to overcome these challenges, the industry must evaluate how best to plan and execute projects in order to make a step change in decommissioning cost reduction.

Direct combustion of cuttings collected at the rig site can help identifying the presence and assess the variation of organic matter into a drilled rock, with minimum sample preparation and signal processing. This near-real-time data provides key information to optimize and de-risk critical decisions such as selection of sidewall coring points, wireline logging programs and sweet spots identification. The method is based on the isothermal oxidation of the sample, done directly at the wellsite and with field deployable equipment. Extensive lab tests have been done to validate both the measurement and the full workflow. Samples have been measured both with this wellsite dedicated equipment and with advanced lab devices. The results between the different methods have been compared and showed good agreement. The workflow has been applied several times to actual wellsite analysis. The results of one of these cases have been illustrated in this paper, together with the integration of the well site TOC with different datastream (i.e. advanced surface fluid logging and continuous isotope logging).

Real-time monitoring of pollutant, toxic and flammable gases is important for health and safety of petroleum extraction and distribution operations. Small, lightweight, fast, low-power, low-cost sensors would enable ubiquitous monitoring of these gases, which would allow for prevention of exposure or explosions and aid in rapid response to hazardous leaks. Currently, there are many methods of detecting such gases, but most sensors suffer either from slow response times, high power consumption, high cost and/or inability to operate in harsh conditions. Here we demonstrate a small, low-cost, low-power, highly sensitive and selective nanomaterials-based gas sensor, specifically targeted for the detection of hydrogen sulfide (H 2 S). A network of WO 3 nanoparticles is heated by an on-chip microhotplate while the conductance of the network is monitored. The device can be heated with short pulses (<100 ms) without diminishing the sensor response, thereby drastically lowering the power consumption to less than 1 mW. The sensor shows high sensitivity to H 2 S, but it does not have direct cross sensitivities to H 2 O or CH 4 , two gases likely to be seen in industrial operation. This low power H 2 S sensor has been integrated into a low cost, stand-alone monitoring system capable of measuring multiple environmental conditions, including temperature, humidity, and H 2 S concentration, and distributing that information via wireless protocols, namely 802.15.4 and 802.11 (WiFi). These environmental detection systems can communicate directly to smart phones via WiFi or be configured into a wireless mesh network of detection systems capable of relaying real-time environmental conditions and location to a safety monitor at a remote location. The nanoparticle-based sensor and integrated detection system developed here, once packaged as a fully manufactured tool, can enable a low-cost solution to real-time monitoring of environmental conditions that will greatly reduce the likelihood of hazardous conditions becoming disasters.

NUGGETS subsea development in the Northern North Sea consists of 5 gas wells with 40 – 70 km tie-back to the Alwyn platform with 1st gas in 2001 and a peak production of 6 MMSCM/D of gas in 2004. Project life was expected to be 10 years with main constraints being methanol requirements for hydrate management and sealine minimum turndown. Due to increasing water production, the wells were shut-in one after the other and the field was due to be decommissioned in 2010. At that time, minimum recommended MeOH concentration was ≈ 28% (wt/wt) which allowed a maximum water production of 40 Sm3/d. Thanks to a concerted effort to keep gas rates at targets which respected all constraints and reduce methanol use to zero, an additional 2.8 MBOE has been produced from NUGGETS. This represents an incremental recovery of about 2.0%. In addition, the field life has been extended with the possibility of further prospects being tied-in to the existing facilities. With methanol constraints removed, new issues are subsea system life longevity and reservoir management. Current field operations philosophy is optimised to respect minimum turndown of the subsea line and the minimum gas rate per well with/without water production. It is also aimed to manage water coning in the reservoir. The reservoir has very high permeability with Kv/Kh ≈ 1 and strong aquifer influx. Moreover, numerical as well as analytical methods were used to investigate the coning. This paper provides a critical assessment of the methods employed from a flow assurance, a well performance and a reservoir management point of view. It concludes with a set of observations and recommendations for operators of dry gas fields with strong aquifers and long subsea tie-backs.

Developing a cost-effective scale management strategy as early as possible during field development planning is imperative to allow informed decision making. In the past, strategy selection was commonly based on static scaling risk assessment. However, the trend over the years has shifted to incorporate dynamic aspects, notably in-situ scale precipitation in a time lapse manner and coupling this with scaling risk assessments. More recently, streamline simulation techniques have been applied to support the prediction of scale precipitation in the reservoir and consequent in-situ stripping of scaling ions. It remains pertinent to extend the use of these dynamic tools to properly assess the impact of reservoir scaling reactions on scale management economics and the subsequent adoption of an optimum strategy. A robust and systematic approach has been developed to combine the use of dynamic models in scaling risk assessment with envisaged production improvement processes and integration of disciplines in the decision analysis process. Reservoir scaling reactions are modeled using streamline simulation. Examinations have been extended to cover the impact of in-situ scale precipitation, taking into account changes in drainage radius in the presence of hydraulic fractures and different sandface completions. Emphasis is also placed on conducting analyses to address field complexities ranging from a variety of potential field development concepts, injection water alternatives, and drainage and completion options to uncertainties in formation water composition. Workflows developed on a North Sea green field development are described, including results from analog/synthetic datasets as examples for this paper. Our work indicates that both in-situ ion stripping and drainage patterns significantly influence chemical requirements and treatment frequencies for squeeze treatments following in-situ scale deposition. Based on this information, comparative scale management costs are developed to help select the most appropriate scale management option. Finally, we highlight limitations in current industry tools and workflows and what can be done to reduce uncertainties during the development of a scale management strategy.

Development of U.S. shale plays has greatly accelerated throughout the past decade and will continue to contribute increased production of gas and hydrocarbon liquids for many years to come. A March report by HIS-Cambridge Energy Research Associates estimates that in 2000, shale gas was only 1% of total production in the U.S., but it now makes up approximately 20% of the total production with the potential to contribute greater than 50% by 2035. The two main technologies attributed with the successful growth in shale-play development are horizontal drilling and fracturing technologies. Coiled-tubing (CT) equipment and technologies have also aided in the rapid and economical development of shale plays. The demand for these services has increased such that a CT unit is now assigned to each frac crew. Because of CT's capability to continuously circulate, work with live-well pressure, and push to the toe of long, horizontal sections, several tools and methods have been devised to transfer these advantages to stimulation and well-servicing solutions to help optimize production while minimizing time and cost. These technologies include hydrajet and CT-conveyed perforating techniques as well as accurate placement of stimulation treatments with precise and instantaneous proppant-concentration control. Larger CT sizes are being used to enhance treatment rates, service longer horizontals, and provide additional weight or force at the end of the tubing for plug drillouts or manipulating service tools. The trend in longer and larger CT size is also driving the need to optimize the CT unit design to maintain operational efficiency and safety as well as meet Department of Transportation (DOT) regulations. This paper reviews these new CT techniques and trends being used to improve shale play developments with case histories. The successes demonstrated in the U.S. are now being targeted at shale-play developments in the eastern hemisphere and Latin America to meet their growing demand for clean and economical energy.

Abstract Wellbore instability in shales is the most challenging and costly issue in drilling operations. Wellbore instability in shales can be attributed to many factors some of which have been well studied and documented. However, the physicochemical and mechanical properties alterations in shales which eventually leads to wellbore failure have been largely ignored. Water and ions movement in and out of shales plays a major role in the alteration of the physicochemical and mechanical properties of shales thus leading to wellbore instability problems and possible hole collapse. Water and ions can move in and out of shales by many mechanisms including, but not limited to, diffusion osmosis, chemical osmosis convective flow and capillary suction. This work presents experimental data analyzing the impact of chemical osmosis, and diffusion osmosis on water and ion movement when shale interacts with drilling fluids. The adopted experimental work minimized the effect of convective flow and capillary suction. Results show that water movement is not only controlled by chemical osmosis (water activity) as previously thought, but is also influenced by diffusion osmosis. This insight provides information and guidelines to optimize drilling fluids to effectively control and mitigate wellbore instability when drilling through troublesome shale. Furthermore, pressure transmission tests were used to experimentally measure capillary entry pressures of various non-wetting fluids (oil-based mud, crude oil and Nitrogen gas) through shales. These capillary entry pressures are needed for the estimation of shales seal capacity (h). Introduction The unfavorable interaction between shale and drilling fluids is considered to be the primary cause of many wellbore instability problems (Chenevert et al, 1969). Such interactions are very complicated and include mechanical, chemical, physical, hydraulic, thermal, and electrical phenomena (Van Oort et al, 1995 and Van Oort, 2003). The overall effect of these interactions is mainly related to the movement of water and ions into or out of shales (Al-Bazali, 2005). The physico-chemical and mechanical properties of shale around the wellbore, such as permeability, strength, pore pressure, and elastic modulus can greatly be altered by such movement. It is well-accepted that the adsorption of water results in shale strength and elastic modulus decrease, swelling and pore pressure increase (Hale et al, 1992).These changes around the wellbore may cause wellbore instability problems during drilling and completion operations. The magnitude of water movement and the effect of absorbed water on shale properties are influenced by the presence of ions in the solution (Ballard T. J. et al, 1992).Ionic diffusion may also result in the movement of ions into the shale formation, resulting in chemical alteration (Gazaniol et al, 1994). Horsrud et al. (1998) found the adsorption of potassium ions caused shale shrinkage due to cation exchange. Others have found that swelling can occur due to other ions and not necessarily potassium ions (Ewy & Stankovich, 2002). Simpson and Dearing (2000) experimentally demonstrated that ion diffusion altered the fabric of the shale and caused shale failure. From the above review, it was found that the movement of water and ions into or out of shale is critical to wellbore instability. Water and ions can move in and out of shales by many complicated mechanisms. These mechanisms include, but not limited to, chemical osmosis, diffusion osmosis, capillary suction and convective flow. In this work, we focused on the diffusive flow of water and ions. Namely, we investigated the impact of both chemical osmosis and diffusion osmosis on shale alteration. Our experimental set up and procedure was designed to minimize the impact of convective and capillary flow.

Abstract Formation of gas hydrates can lead to serious operational, economic and safety problems in the petroleum industry due to potential blockage of oil and gas transmission lines and processing facilities. Thermodynamic inhibitors are widely used to reduce the risks associated with gas hydrate formation. In practice, the aqueous phase in which inhibitors are added already contains electrolytes from either drilling/completion fluids or from formation water. In such mixed inhibitor systems, both co-solvents and strong electrolytes are present in the aqueous phase, making the thermodynamics of these highly non-ideal systems difficult to model. Hydrate/aqueous and hydrocarbon PVTX thermodynamic modelling at Heriot-Watt University (HWHYD) dates back over 25 years. In the latest version of the HWHYD model (2.1), a new approach has been introduced and applied for modelling phase equilibria in systems containing components which can form hydrogen bonds (e.g. water, methanol, ethanol, mono-ethylene glycol, and etc) and hydrocarbon mixtures using a robust general-purpose implementation of the CPA (Cubic Plus Association) model. This work is evaluating the capability of this model for conventional and challenging hydrates calculations, including; gas hydrate in low water content gases, hydrate stability zone in the presence of high concentration of inhibitor(s) or salt(s) and/or high pressure conditions, hydrate stability zone of oil/condensate in the presence of produced water and inhibitors, and prediction of hydrate inhibitor distribution in multiphase systems. The results show that the Heriot-Watt Hydrate (HWHYD 2.1) software predictions are consistently in a good agreement with experimental data. Introduction Deepwater oil and gas exploration has increased significantly in recent years, with forecasts predicting that this trend will continue. The deepwater environment can expose productions lines to low temperatures, which can create production problems in subsea flowlines due to the formation of gas hydrates. These plugs can take weeks and even months to dissociate. Not only do these plugs cause a loss in production, but they also create a severe safety hazard. Accurate knowledge of hydrate phase equilibrium in the presence of inhibitors is therefore crucial to avoid gas hydrate formation problems and to design/optimize production, transportation and processing facilities. Historically, the formation of gas hydrates in subsea production facilities has been managed by keeping the fluids warm, removing water, or by injecting thermodynamic inhibitors. The most common of these hydrate inhibitors are methanol (MeOH) and glycols such as monoethylene glycol (MEG). Therefore there has always been industrial interest in improving the reliability of the models to predict phase behaviour of gas hydrate systems, especially for systems containing both organic inhibitors and electrolytes, the so-called mixed inhibitor systems. In this work, a thermodynamic model using the well-proven Cubic-Plus-Association (CPA) equation of state (Kontogeorgis et al., 2006) has been employed to model the phase equilibria. The thermodynamic model is based on uniformity of fugacity of each component throughout all the phases. The hydrate phase is modelled by the solid solution theory of van der Waals and Platteeuw (1959) using a Kihara potential model (Kihara, 1953) to calculate the potential function for compounds forming hydrate phases.

Abstract The CO2CRC Otway Project, in Victoria, Australia, is one of the first projects of CO 2 storage in a depleted gas reservoir. CO 2 injection in the sandstone reservoir, at a depth of 2,000 mSS, started in March 2008 with the objective to inject up to 100,000 tonnes of CO 2 over two years. This study compares the level of predictability obtained with different cases depending on the initial data, using the same numerical compositional simulation package. We use recorded data (production and injection) to build a new numerical reservoir model. A dynamic model had already been built before the injection well started (Xu et al., 2006) and was validated by history matching using the gas production data reported. In this paper, we used the same updated static model (Dance et al. 2007) as used for the pre-injection model, which is based on the production data and the data obtained from the injection well (CRC-1). With this updated static model, a different dynamic model is built using injection data and through a newly developed simulator option, which better simulates the CO 2 -water behavior. The injection rate and pressure data from CRC-1 are now available and the actual breakthrough time - at which the CO 2 plume reached the monitoring well (Naylor-1) located 300 m away from CRC-1 - can be history matched. Various relative permeability curves including new laboratory measurements performed on a core taken from the reservoir formation (Waarre C) were used. The results from the updated dynamic modeling using this measured relative permeability data are compared to results using data from literature. In general, experimental measurements for drainage and imbibition processes are not available This study gives a better understanding of the parameters which strongly influence simulated CO 2 behavior. It shows the relation between the data availability and prediction reliability. Introduction Carbon dioxide is a greenhouse gas and has a strong impact on global climate changes. The effect of CO 2 on global warming is now well recognized and possibilities to reduce the greenhouse gas emissions are currently investigated. It is not expected that the demand of fossil fuels, which produce most of the greenhouse gases (GHG), will decline in the near future (International Energy Agency, IEA) although significant efforts have been made to use more alternative energy sources. Carbon capture and storage (CCS, i.e. injection of CO 2 in deep geological formations instead of being emitted in the atmosphere) is recognized as to be one of the options to reduce the emissions of GHG as described by the IEA (2008) and by the Intergovernmental Panel on Climate Change (Fisher et al., 2007). More and more CCS projects are being developed around the world. Lately, with the support of IEA and to respond to a request from the G8 nations, a CCS Roadmap has been developed to demonstrate and effectively deploy CCS projects.

Abstract From 2002 to 2008 the oil discharge has been reduced by 10% despite an increase in the produced water discharge of 230% (Figure 1). This has been achieved by reducing the average oil concentration in the produced water to 9 mg/l in 2008. Significant reductions have especially been recorded from 2007 to 2008. The reductions are primarily a result of the following initiatives. ○ Rerouting of recycles - rerouting of e.g. used H2S scavenger have improved separation and produced water treatment ○ Individual KPI's for the different produced water treatment systems ○ On-line cleaning of the produced water treatment systems ○ System analysis - continued optimisation of the separation and produced water treatment systems This paper presents the significant reductions that have been achieved primarily through technical improvements and better operation of the installed equipment.

Abstract There has recently been Conceptual and FEED studies to convert existing hydrocarbon producing facilities to CO 2 injection. Often the most cost effective option for CO 2 injection is when combined with enhanced hydrocarbon recovery. This new operation, however, increases levels of risk; the additional CO 2 gives rise to a new asphyxiate hazard, while the increased CO 2 in the Process stream brings its own production and safety trade-offs. This paper addresses these hazards and the conundrum of optimising production and safety. Presented herein is an integrated Process and Safety Engineering approach to control the risks and develop a decision making framework to allow confidence for the safe design of future CO 2 injection Projects. INTRODUCTION In recent years, it has been recognised that the threat of climate change, due to the emission of greenhouse gases, particularly carbon dioxide (CO 2 ) is one of the key environmental concerns facing modern society. It is recognised that carbon Capture and Storage (CCS) is one of the most effective means of preventing carbon discharge, with many sites in the UK identified for this technology. Furthermore, recent research by Edinburgh University, sponsored by the Scottish Government, indicates that this technology may outstrip oil and gas in the importance to UK economy. This paper attempts to show that there is only a small step from rhetoric to implementation. The developments at the Power Station phase of CCS are recognised (ref 1) but it is the detail of the other phases that is missing: In particular the carbon reception facilities and the injection and storage and, if applicable, the miscible flood which is one of the forms of extended oil recovery (EOR) available from CO 2 injection. This paper offers detail to these latter phases, from the key development questions f robustness of business case through to detailed technical requirements and the management of any potential show stoppers. PHASES OF CCS DEVELOPMENT There are three phases of concept development and selection processes: Onshore: The generation of 'carbon free' electricity through either the construction of a gas reformer and new turbines to run on hydrogen or by the addition of post combustion carbon capture equipment, as detailed in reference 1 and in the current trails at Longannet. Transportation: The pressurisation and transportation of the captured CO 2 through an existing pipeline to an offshore oil and gas platform.

Abstract The increase in produced water has led to a growing need from E&P operators for better oil in water monitoring systems. Roxar has developed an inline and online oil-in-water monitor suitable for topside discharge and re-injection applications, based on ultrasonic technology. The first Roxar Oil-in-water monitor was installed in May 2006 on Statoil's Sleipner A platform in the North Sea. Statoil is using the monitor to measure overboard water discharge, ensuring that it meets environmental requirements and efficiently monitors the separation process. Immediately after installation, attempts were made to introduce increasing amounts of oil into the produced water stream to verify that the monitor registered oil concentration changes accordingly, which it did. Periods with distinctly higher concentration levels were also analyzed. The rapid change in water level in the separators corresponded to an increase in the oil-in-water concentration downstream. During the trial phase, reliability and robustness have been demonstrated, and this paper describes how the ultrasonic measurement techniques, combined with a novel reflector design, helps the operator obtain accurate oil concentration readings even during and after experiencing production instability. This paper presents results from the pilot, verifying the performance of online oil in water monitoring and its ability to operate at different concentrations. The pilot to date has confirmed the monitor's ability to provide accurate information to Statoil on the size distribution and concentration of oil and is already playing a key role in monitoring Statoil's overboard discharge and separation process. The Increase in Global Water Production The last few years have seen a significant increase in global water production in the oil and gas industry. Whereas today current oil production is 80 million of barrels per day approximately, current estimates of global water production are 250 million barrels per day - a three to one ratio. Today, the average water cut globally is 75 per cent - a five per cent increase on water cuts ten years ago. The increase in produced water is being seen on the Norwegian Continental Shelf (NCS) where water/oil ratios have increased over the last years and annual emissions of oil into the sea are estimated at 3000 tons of oil [1]. This increase in produced water and oil discharge on the NCS are expected to continue at least for the next five years. With this increase in produced water has come the increased need from operators for detailed information on the size and amount of sand and oil in produced water - whether it is reinjection, discharged or processed water. There are a number of drivers for this: Operator Drivers for Better Oil in Water Monitoring 1) Optimizing Production. There are several ways by which increased oil in water monitoring can optimize offshore production. – There is the increase in revenue by separating the oil from the produced water. According to energy industry analysts Douglas-Westwood, 2.1 million barrels of oil are lost every day due to oil being lost through produced water discharge [2]. – There are other potential problems during the production phase that can be alleviated through produced water monitoring. This includes the plugging of disposal wells by solid particles and suspended oil droplets, the plugging of lines, pumps and valves due to inorganic scales, and corrosion due to the electrochemical reactions of the water with piping walls.

Abstract Liquid loading in gas wells is a phenomenon that increasingly limits production in mature gas wells where reservoir pressures are insufficient to lift liquids out of wellbores. Various technologies to artificially lift liquid associated with gas production exist, however in offshore fields most of them are not applicable for well completion or legal requirements. In the past soap sticks have been tried to foam up liquids, however these may never have reached the area where liquid had accumulated due to wellbore deviation. It was therefore decided to try liquid batch injection in several North Sea gas wells. The paper speaks about candidate selection, chemical screening, laboratory testing, operational considerations and the results of the offshore field trials. The results from the first trials were above expectations. One cycling well was able to be kept online five times longer than under normal operating circumstances, while for another well, its time online more than doubled. These results were the trigger for the next two sets of surfactant trials in the southern North Sea region, which were again successful. In one well a downhole gauge was utilised to monitor the dramatic change in well behaviour, which gave great insight into the way the surfactant acted. This is discussed in detail in the paper. No foam-related problems were encountered at the platform as defoamer was injected at surface. From these successful North Sea surfactant batch trials, it can be concluded that de-liquifying gas wells with the aid of surfactants can be a very effective and cheap way to increase gas production, mainly by keeping wells online for an extended period of time. Resolving the issue of liquid loading in maturing gas fields across the North Sea will lead to higher production rates (up to 30% from cycling wells) and an increase in reserves recovery. Introduction Gas assets in the southern North Sea region are becoming increasingly mature. The wells are completed with - compared to North American gas wells - fairly big tubing diameters (typically 4.5" in North Sea gas wells compared to 2 3/8" in North American wells). This means, that North Sea gas wells start to liquid load at significantly higher gas rates than North American gas wells. Typical critical rates - based on the Turner model - for liquid loading in the North Sea are between 3 and 7 [MMscf/d], depending on the tubing inside diameter. However the Turner criteria can only be used as a rough guideline in North Sea gas wells, because it is only reflecting reality in vertical wells in mist flow. However, it has been confirmed with field experience, that the order of magnitude of critical rates is in the right area. Some in-house modifications, which might be published in a separate paper, can bring Turner's criteria for critical rate even closer to reality. The Turner criteria is based on the observation, that a gas well starts to load with liquid if a single droplet of fluid cannot be lifted, which means the drag force equals the gravitational force. From that point in time onwards, liquid cannot be lifted out of the wellbore, which defines the onset of liquid loading. Figure 1 illustrates the Turner droplet model. Equation 1 gives the formula for critical velocity, Equation 2 for critical flow rate.