A New 3-D Numerical Model to Effectively Simulate Injection Tests

Abstract

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 As a consequence, the conventional analytical approach used to describe the pressure transient behaviour is no longer applicable, and only numerical simulations can thoroughly describe the evolution of saturation and pressure fields in the reservoir during injection and subsequent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.

Harmonic Pulse Testing for Well Monitoring: Application to a Fractured Geothermal Reservoir

“…It has gained attention over the last 20 years in the oil and gas industry (El-Khazindar et al, 2002;Hollaender, Filas et al, 2002;Verga & Rocca, 2010;Rocca & Viberti, 2013;Verga & Rocca, 2010;Verga & Salina Borello 2016;Woie et al, 2000). Some authors have dedicated to the study and development of interpretation methodologies based on analytical models (Banerjee et al, 1998;Barreto et al, 2011;Boughrara et al, 2007;Habte & Onur, 2014;Levitan, 2003), numerical models (Verga et al, 2008(Verga et al, , 2014, or hybrid interpretation approaches that adopt numerical simulation along with standard monophasic models (Verga et al, 2011(Verga et al, , 2012. Successful real cases have also been documented (Azzarone et al, 2011;Beretta et al, 2007;Tripaldi et al, 2009).…”

Environmental Sustainability of Oil Industry

“…As a consequence, injection tests eliminate emissions during reservoir appraisal and, except for fluid sampling, can provide all the information needed to estimate the well productivity at a reasonably low cost and with a good degree of reliability (Levitan, 2002;Beretta et al, 2007). Since the physical phenomena characterizing injection test are different with respect to the conventional well test, numerical models capable to provide a reliable interpretation of the data have been developed over the last years (Verga et al, 2008;Cancelliere and Verga, 2012). An example of successful field experiences was presented in the study by Beretta et al (2006;.…”

A new insight for reliable interpretation and design of injection tests

“…Levitan (2002) and Sosa et al (1981) compared the results obtained with different sets of permeability curves focusing on the end point values. The effect of the end points on the Corey-shaped permeability curves was also investigated by Verga et al (2008), who observed that the magnitude of the bi-phase skin strongly depends on the relative permeabilities through the mobility ratio. It was observed that, if the mobility ratio and the Corey exponents were unchanged, approximately the same bi-phase skin values were obtained for different combinations of end-points and fluid viscosities.…”