Renzo Angeles

Estimation of Permeability and Permeability Anisotropy From Straddle-Packer Formation-Tester Measurements Based on the Physics of Two-Phase Immiscible Flow and Invasion

We describe the successful application of a new method to estimate permeability and permeability anisotropy from transient measurements of pressure acquired with a wireline straddle-packer formation tester. Unlike standard algorithms used for the interpretation of formation-tester measurements, the method developed in this paper incorporates the physics of two-phase immiscible flow as well as the process of mudcake buildup and invasion. An efficient 2D (cylindrical coordinates) implicit-pressure explicit-saturation finitedifference algorithm is used to simulate both the process of invasion and the pressure measurements acquired with the straddle-packer formation tester. Initial conditions for the simulation of formation-tester measurements are determined by the spatial distributions of pressure and fluid saturation resulting from mud-filtrate invasion. Inversion is performed with a Levenberg-Marquardt nonlinear minimization algorithm. Sensitivity analyses are conducted to assess non-uniqueness and the impact of explicit assumptions made about fluid viscosity, capillary pressure, relative permeability, mudcake growth, and time of invasion on the estimated values of permeability and permeability anisotropy. * Currently with TOTAL

Just-In-Time Perforating for Controlled, Cost-Effective Stimulation and Production Uplift of Unconventional Reservoirs

Recent advances in multi-stage stimulation technologies, including open- and cased-hole types, have largely overlooked the advantages of single-zone stimulation due to hardware and cost limitations. In most conventional methods, multiple perf clusters are treated at once using one single frac stage with the expectation that equally-stimulated fractures will be created at each perf cluster within tens and hundreds of feet. This creates over-stimulation in some perf clusters and under-stimulation in others, which unveils the current economic and practical limits of effectively creating fractures where needed, not where it is possible to place them. Other methods use a large number of frac plugs which require additional wireline trips and later need to be drilled out, increasing the total cost and mechanical risk of the completion. As lateral length increases, many operators also face the challenge of not being able to remove all frac plugs due to coiled-tubing depth limitations. This paper introduces the recent implementation of Just-In-Time Perforating (JITP) in shale gas, unconventional plays. JITP is one of the Multi-Zone Stimulation Technologies (MZST) developed and patented by ExxonMobil over a decade ago and extensively used in vertical and S-shaped wells in the Piceance basin, Colorado, and recently implemented in the XTO Fayetteville Shale, Arkansas. JITP creates multiple single-zone fracture stimulations on a single wireline run using ball-sealer diversion and perforating guns that remain downhole during fracturing. Other key features of this method are the use of less horse power, significant reduction in the number of frac plugs, fewer wireline runs, and added flexibility in water management. This paper describes the technical advantages and business justification for applying JITP in unconventional resources and also provides preliminary results from the performance of the JITP field trials in horizontal wells.

Advancing Multi-Stage Fracturing Using Horizontal JITP and Autonomous Completion Systems

The execution and optimization of multi-stage fracturing treatments remains one of the most critical steps in the economic development of unconventional resources. Two recently developed and field tested technologies offer a step-change in fracturing operations: Horizontal Just-In-Time Perforating (JITP) and Autonomous Completion Systems. While JITP is a well-established technique (extensively used in the Piceance basin, Colorado), its application to horizontal wells is relatively new and promises improved single-zone stimulation, significantly less use of horsepower, reduced number of frac plugs, and added flexibility in water management. In addition, ExxonMobil is actively progressing its proprietary Autonomous Completion Systems that maximize surface equipment utilization by removing the need for umbilical intervention (wireline, coiled tubing, or tractors), which also eliminates the need for lubricators, lifting equipment, additional personnel and vehicles, and improves safety. This paper presents the latest milestones achieved in the development of these completion technologies. The application of JITP to horizontal wells was recently successfully confirmed with a comprehensive pilot program that included more than 30 wells and over 1400 single-zone treatments. Likewise, Autonomous Completion Systems entail broader applications beyond perforating systems. The key enabler for this technology is the frangible downhole navigation system which is undergoing field testing. In addition, the autonomous completion components are fully friable and do not require additional retrieval runs. The use of these technologies is anticipated to create new opportunities in equipment utilization efficiency and operational flexibility to the multi-stage fracturing methods available in the industry today.

Synthetic and Field Examples of the Estimation of Capillary Pressure and Relative Permeability From Formation-Tester Measurements

Laboratory measurements of relative permeability and capillary pressure are seldom performed on core samples retrieved from petroleum-production wells. Reservoir engineers rely on a limited number of small core samples to characterize many of the large-scale multiphase flow petrophysical properties affecting the production and recovery of hydrocarbon fields. The question also remains whether laboratory measurements are truly representative of in-situ rock properties. Non-linear regression methods were recently proposed to estimate saturation-dependent petrophysical properties from fractional flowrate measurements acquired with formation testers. However, such procedures are still unclear to many practicing analysts and to date have not been fully explored with both synthetic and field data. This paper develops and successfully tests a new method to estimate saturation-dependent rock properties on two field data sets. Using in-house and commercial reservoir simulators, we model the processes of mud-filtrate invasion, acquisition of borehole resistivity measurements, and subsequent fluid withdrawal during sampling. In the examples considered, the formation tester consists of a dual-packer module acquiring pressure and fractional flow-rate measurements during the sampling operation. Based on the physics of water-base mud-filtrate invasion, borehole resistivity measurements and dualpacker measurements are first used to estimate both initial water saturation and permeability with initial estimates of capillary pressure and relative permeability. The latter are described with the Brooks-Corey model, which includes 6 independent unknown parameters. Subsequently, the measured pressure and fractional flow rates are used to estimate the 6 Brooks-Corey unknown parameters, thereby defining a new set of capillary pressure and relative permeability curves to refine the estimation of initial water saturation and permeability jointly from pressure and borehole resistivity measurements. This process repeats itself until borehole resistivity, pressure, and fractional flow-rate measurements are all honored within prescribed error bounds. The estimation method satisfactorily reconstructs the relative permeability and capillary pressure curves with minimal apriori information. Whereas the relative permeability end-points of water and oil can be readily estimated in a couple of nonlinear iterations assuming that the remaining parameters are fixed, residual saturations add complexity to the inversion, especially for cases where the fractional flow rate exhibits a sharp decrease in contamination after oil breakthrough. We also investigate the use of Design of Experiment (DoE) tools to secure a reliable initial guess for nonlinear inversion and in understanding the separate contributions of the various measurements to specific inversion parameters. Such information is fundamental to designing a data-weighing scheme that selectively enhances the sensitivity of the measurements to unknown parameters during progressive steps of nonlinear inversion. Introduction The possibility of estimating relative permeability and capillary pressure curves from in-situ measurements has generated substantial interest in the past decades. Investigators have attempted to obtain such curves by matching long-time production data (Al-Khalifa, 1993; Kulkami and Datta-Gupta, 2000, Toth et al., 2006), well tests (Nanba and Horne, 1989; Puntel de Oliveira and Serra, 1995; Chen et al., 2008), and formation-tester measurements (Zeybek et al., 2004; Alpak et al., 2008). The advantages of using formation testers are (a) their flexibility to acquire bottomhole fractional flow-rate measurements (through optical sensors), (b) the ability to control the flow rate of fluid pumpout, and (c) the acquisition of pressures with different monitoring probes concomitant with fluid sampling on a relatively thin rock formation. Other efforts have