The ultimate goal of SENSE is to offer storage site operators a cost-effective monitoring option that can form part of an effective site assurance/monitoring program and feed into workflows for an early alert system to detect unexpected changes in the subsurface.The SENSE project has four demonstration sites for monitoring technologies and developing concepts and procedures. These sites are both onshore and offshore. The onshore sites include In Salah (Algeria) and Hotfield Moors (UK). For these sites, the project will use satellite data to explore the response of the surface to pressure changes in the subsurface. Algorithms for automatic satellite data processing to facilitate quick access to ground elevation data for site operators are under development at the British Geological Survey (BGS) and Norwegian Geotechnical Institute (NGI). The offshore sites include Bay of Mecklenburg (Germany) and the Gulf of Mexico (USA). In addition, the SENSE partners have requested access to data from the Troll Gas Field, the North Sea, to study its subsidence due to production-related pressure reduction. The Troll Gas Field is located next to the storage site considered for the Norwegian Long Ship project, and its data will provide a good understanding of the geomechanics of the area.In this paper, we present the work on the In Salah and the Bay of Mecklenburg sites. New InSAR data from the In Salah are used to evaluate the ground movement during the post-injection period and thus to assess the behaviour of the storage site after completion of the injection phase. Bay of Mecklenburg is an offshore site for field experiment to inject a gas underground, build-up pressure, uplift the seafloor and measure the resulted uplift. The first field campaign at the Bay of Mecklenburg was completed in late 2019. It provided both gravity cores from the seabed and geophysical data acquisition for characterizing the shallow subsurface layers. The gravity cores were characterized for physical and mechanical properties. The material properties were used for simulating injection and response of the seafloor to induced pressure. Geomechanical 2D and 3D simulations show that the reservoir may sustain very low overpressure before it fails. Hence, this magnitude of overpressure may create a seafloor uplift of about a few millimeters to a couple of centimeters. The monitoring techniques are therefore being designed to capture uplift in this order of magnitude during the injection operation.
Heavy oil reservoirs remain challenging for surfactant-based EOR. In particular, selecting fine-tuned and cost effective chemical formulations requires extensive laboratory work and a solid methodology. This paper reports a laboratory feasibility study, aiming at designing a surfactant-polymer pilot for a heavy oil field with an oil viscosity of ~500cP in the South of Sultanate of Oman, where polymer flooding has already been successfully trialed. A major driver was to design a simple chemical EOR method, to minimize the risk of operational issues (e.g. scaling) and ensure smooth logistics on the field. To that end, a dedicated alkaline-free and solvent-free surfactant polymer (SP) formulation has been designed, with its sole three components, polymer, surfactant and co-surfactant, being readily available industrial chemicals. This part of the work has been reported in a previous paper. A comprehensive set of oil recovery coreflood tests has then been carried out with two objectives: validate the intrinsic performances of the SP formulation in terms of residual oil mobilization and establish an optimal injection strategy to maximize oil recovery with minimal surfactant dosage. The 10 coreflood tests performed involved: Bentheimer sandstone, for baseline assessments on large plugs with minimized experimental uncertainties; homogeneous artificial sand and clays granular packs built to have representative mineralogical composition, for tuning of the injection parameters; native reservoir rock plugs, unstacked in order to avoid any bias, to validate the injection strategy in fully representative conditions. All surfactant injections were performed after long polymer injections, to mimic the operational conditions in the field. Under injection of "infinite" slugs of the SP formulation, all tests have led to tertiary recoveries of more than 88% of the remaining oil after waterflood with final oil saturations of less than 5%. When short slugs of SP formulation were injected, tertiary recoveries were larger than 70% ROIP with final oil saturations less than 10%. The final optimized test on a reservoir rock plug, which was selected after an extensive review of the petrophysical and mineralogical properties of the available reservoir cores, led to a tertiary recovery of 90% ROIP with a final oil saturation of 2%, after injection of 0.35 PV of SP formulation at 6 g/L total surfactant concentration, with surfactant losses of 0.14 mg-surfactant/g(rock). Further optimization will allow accelerating oil bank arrival and reducing the large PV of chase polymer needed to mobilize the liberated oil. An additional part of the work consisted in generating the parameters needed for reservoir scale simulation. This required dedicated laboratory assays and history matching simulations of which the results are presented and discussed. These outcomes validate, at lab scale, the feasibility of a surfactant polymer process for the heavy oil field investigated. As there has been no published field test of SP injection in heavy oil, this work may also open the way to a new range of field applications.
Prior to field-scale development of chemical EOR processes, pilot tests are widely accepted in the oil industry as a standard method to determine the efficiency of the formulated chemicals. During such tests there can be significant differences in temperature between the injected and reservoir fluids. This results in a cool-down of the wellbore, near-wellbore and inter-well regions which can be aggravated in high temperature reservoirs. Key features of surfactant flooding, such as interfacial tension (IFT) reduction between the oil and water phases, depend strongly on temperature. As a result it is necessary to estimate the strength of this cool-down effect upon designing pilot tests. This is the topic of this paper which addresses several scales ranging from near-wellbore to pilot pattern. This work assesses the impact of temperature gradients during a pilot test on the efficiency of surfactant injection using advanced reservoir simulation. We first determine the temperature window seen by an injected surfactant solution with the aim of understanding how it may drive surfactant formulation. We then apply our findings on a pilot design study, with a model including a temperature dependent IFT. We analyse the sensitivity of given injection sequence and operational constraints to specific properties of the injected surfactant solution (low-IFT temperature windows) and then propose a methodology to determine the most efficient injection sequence for a specific surfactant formulation. We show that the temperature window encountered by the surfactant is very sensitive to thermal history of the reservoir and injection temperature. The analysis of chemicals slug thermal and compositional mixing with in-situ fluids is found to be a game changer for reliable pilot design and production forecasts. Obtaining the lowest IFT between oil and water phases is the key in surfactant flooding efficiency: as such the in-situ temperature profiles obtained by simulation and the formulation design at the laboratory should be closely linked. We demonstrate that the process is considerably sensitive to temperature and suggest as a result the following workflow for the design of injection sequences during a pilot test: 1) assessing the temperature window that will be seen by the surfactant using simulation, 2) designing an adequate surfactant formulation, 3) estimating an optimal and robust surfactant injection sequence using simulation, 4) iterating between the three previous steps until an optimal recovery is achieved with a laboratory-formulated, cost-effective surfactant. The impact of temperature on surfactant pilot tests is a specific, not so well documented subject, although it is a capital step in the feasibility assessment of a field scale deployment of surfactant EOR technology. Our workflow yields a reliable assessment of temperature landscapes seen by the injected fluids, which may then be used to test surfactant formulations from near-wellbore to interwell/reservoir scale (e.g. for designing and performing single well chemical tracer tests). As such it should be of interest to petroleum engineers, production engineers and chemists working on the design of chemical EOR processes.
An accurate evaluation of injectivity is essential to the economics of any chemical EOR process. Most commercial simulators enable non-Newtonian behaviour modelling but it is often overlooked due to inadequate grid resolution. Indeed, in cases where shearthinning fluids are injected in a reservoir, shear rates and viscosities in the vicinity of the wellbore can be poorly estimated if the spatial resolution of the well grid-blocks is too coarse. This results in biases in injectivity and economics which we discuss here in the context of foam-based displacements. We consider continuous foam injection in models of different spatial resolutions ranging from 1 to 100 m gridblock sizes and study the behaviour of injection wells obtained on the coarser grids compared with the results from a high resolution grid. This reference grid is sufficiently refined to account for near-wellbore large velocity gradients and render injectivity accurately. In this work we propose new formulations of the well index that capture shear-thinning behaviour that the conventional Peaceman calculation fails to address. We first demonstrate that a poor evaluation of near-wellbore velocity leads to erroneously degraded injectivity on the coarser grids when compared to the reference grid. In order to correct these errors our modified well index is applied and validated in various scenarios of foam displacement simulation with radial grids. It captures a more accurate injectivity than the conventional Peaceman calculation once steady-state regime is reached. The modified well index we propose, used under a simplified form as direct input in reservoir simulation, significantly enhances injectivity estimates without resorting to grid refinements or modifying the shear-thinning model of the injected foam. In most cases it yields results that are closer to those obtained using grid refinements than the Peaceman formula at a much more attractive computational cost. Additional work remains to complete our understanding of injectivity in more complex settings, especially in the context of foam injection when effects such as foam dry-out and destruction in the presence of oil are as important on sweep efficiency as its shear-thinning behaviour. Our workflow successfully corrects biases in the estimation of injectivity and yields more accurate results and avoids resorting to time-consuming methods such as grid refinements and physical input data alteration. Moreover it is simple to implement in most commercial simulators and does not require using empirical criteria. However, it bears some limitations which we also discuss.
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