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Summary Gas reservoirs are generally subject to non-Darcy effects, especially in the near-wellbore zone. In fact, the assumption of Darcy-flow regime is no longer valid because of inertial phenomena and/or turbulence. These could significantly reduce the peak performance of a gas well. Therefore, characterization and monitoring of the non-Darcy effects is key for defining an optimal reservoir-exploitation strategy. This is particularly true in the case of storage fields, where withdrawal- and injection-gas rates are typically very high (hundreds of thousands of m3/d) and determining and monitoring well performance is key to ensuring that deliverability meets demand and/or contract obligations. Pulse testing, which is dependent on a periodic variation of produced/injected rate, is an effective methodology to test a well during ongoing field operations without stopping production. Although pulse testing is very promising for monitoring well performance, it has never been exploited for this purpose. In this paper, the development of a method for pulse testing high-performing gas wells is presented and discussed. The pressure response to the imposed rates is analyzed in the frequency domain to evaluate reservoir and well properties. An analytical solution in the frequency domain taking into account wellbore-storage effects was derived. The method was applied to test a real gas well of a storage reservoir under two different pressure conditions to assess the effect of turbulence on deliverability. Although the pulse-testing technique might not replace traditional well testing for determining reservoir properties, it can be successfully applied to monitor well performance as a function of reservoir pressure.

Harmonic Pulse Testing (HPT) has been developed as a type of well testing applicable during ongoing field operations because a pulsed signal is superimposed on background pressure trend. Its purpose is to determine well and formation parameters such as wellbore storage, skin, permeability, and boundaries within the investigated volume. Compared to conventional well testing, HPT requires more time to investigate the same reservoir volume. The advantage is that it does not require the interruption of well and reservoir injection/production before and/or during the test because it allows the extraction of an interpretable periodic signal from measured pressure potentially affected by interference. This makes it an ideal monitoring tool. Interpretation is streamlined through diagnostic plots mimicking conventional well test interpretation methods. To this end, analytical solutions in the frequency domain are available. The methodology was applied to monitor stimulation operations performed at an Enhanced Geothermal System site in Pohang, Korea. The activities were divided into two steps: first, a preliminary sequence of tests, injection/fall-off, and two HPTs, characterized by low injection rates and dedicated to estimate permeability prior to stimulation operations, and then stimulation sequence characterized by a higher injection rate. During the stimulation operations other HPT were performed to monitor formation properties behavior. The interpretation of HPT data through the derivative approach implemented in the frequency domain provided reliable results in agreement with the injection test. Moreover, it provided an estimation of hydraulic properties without cessation of stimulation operations, thus confirming the effectiveness of HPT application for monitoring purposes.

 Stratigraphic Forward Model (SFM) provides channel body volumetrics at basin scale  Basin-scale constraints from the SFM were integrated into reservoir models  Uncertainty of basin-fill parameters was propagated to reserve estimation  Inference of basin-fill parameters from reservoir data reduced their uncertainty

This paper presents a critical review and the state of the art of graphene porous membranes, a brand-new technology and backdrop to discuss its potential application for efficient water desalination in low salinity water injection (LSWI). LSWI technology consists in injecting designed, adequately modified, filtered water to maximize oil production. To this end, desalination technologies already available can be further optimized, for example, via graphene membranes, to achieve greater efficiency in water-oil displacement. Theoretical and experimental applications of graphene porous membranes in water desalination have shown promising results over the last 5-6 years. Needless to say, improvements are still needed before graphene porous membranes become readily available. However, the present work simply sets out to demonstrate, at least in principle, the practical potential graphene membranes would have in hydrocarbon recovery processes.

Conventional well testing is becoming less and less attractive due to environmental constraints and high costs. It is likely that injection/fall-off tests will largely replace the conventional production/build-up sequence since they eliminate surface emissions and can significantly reduce testing costs. However, the welltest interpretation is complicated because of the presence of two phases, the fluid originally in place (hydrocarbon) and the injected fluid (diesel or brine). Fluid saturations vary during injection and the assumption of a piston like displacement is valid only for very favourable mobility ratios. Thus the variation of fluids distribution with time is governed by effective permeabilities, but also gravitational and thermal gradients, heterogeneity and anisotropy might strongly affect the flow. As a consequence, the conventional analytical approach used to describe the pressure transient behaviour is no longer applicable, and only numerical simulations can thoroughly describe the evolution of saturation and pressure fields in the reservoir during injection and subsequent fall-off. The correct determination of the fluid distribution is critical for evaluating the skin due to the presence of two phases in the reservoir, and in turn the skin value, together with permeability, is essential to calculate the well productivity. A new near wellbore, 3D numerical model was developed and implemented for properly designing and interpreting injection tests in both oil and gas reservoirs. The model accounts for all the aspects that can impact on fluid and pressure distribution. The simulation results are provided in terms of pressure and pressure derivative for subsequent analyses. The reliability of the results were verified against commercial well testing software packages under simplified conditions, i.e. isotropic and homogeneous formation, negligible gravitational, capillary and thermal effects. The advanced options of the model were then applied to simulate injection tests with thermal exchange between fluids in oil and gas reservoirs. The results are presented in this paper. Introduction Well tests have been widely used for several decades in the oil industry for evaluation of the well productivity and formation damage, estimation of reservoir characteristics such as initial pressure, fluid type, effective permeability and identification of reservoir barriers or boundaries, which are key information for field development and facilities design (Coelho, 2005). However the evolution in HSE's politics and economic considerations have changed the viewpoint with which conventional well tests are evaluated. In fact during exploration activities it is a common practice to burn the produced fluids because there is no infrastructure and equipment in place to collect the hydrocarbons produced during well tests. Thus significant amounts of emissions that contain unburned hydrocarbons, carbon monoxide and nitrogen oxides are produced. Where this is no longer acceptable conventional testing becomes unfeasible. On the other hand, economic considerations tend to be one of the main reasons for not testing as performing a well test typically costs several million dollars mostly due to required rig time and loss of production. Due to the high costs involved in well test operations, especially in offshore exploration wells, the test type must be carefully chosen and properly designed in order to meet its required objectives at the lowest cost (Hollaender et al., 2002). Therefore, the current industry drivers demand short, cost-effective, and environmentally friendly test procedures, especially in exploration wells. This is particularly true in deepwater and arctic environments where conventional tests can be prohibitively expensive or logistically not feasible (Soliman et al., 2004 and 2005). Most disadvantages could be minimized or even suppressed with emission-free well testing (Hollaender et al., 2002). Whether suitable alternatives can be found for sampling and reservoir parameter estimation is the subject of regular debate (Whittle et al., 2003). A review and discussion of technologies such as mini-DST, Close Chamber Testing, production/reinjection tests as viable alternatives to conventional well testing can be found in the technical literature (Beretta et al., 2006 and 2007; Banerjee et al.,1998; Coelho et al., 2005; El-Khazindar et al., 2002; Hollaender et al., 2002; Woie et al., 2000) and is beyond the scope of this paper.