Mark A. Proett

Inversion of Multi-Phase Petrophysical Properties Using Pumpout Sampling Data Acquired With a Wireline Formation Tester

Modern pumpout wireline formation testers (PWFTs) can collect a wide array of data during the pumpout phase of fluid sampling. Both flow rate and pressure are sampled in time during the pumping process and are used to infer apparent permeabilities under the assumption of single-phase fluid flow. Numerical simulation of multi-phase flow has been successfully used to describe filtrate invasion and the resulting pumpout contamination as a function of pumping time and rate. Recent developments in invasion modeling also allow one to simulate the invasion profile for either water-base or oil-base filtrate invasion when the mud properties are coupled to the invasion process. Because of these developments, it is now possible to determine more complex multi-phase petrophysical properties of rock formations. In this paper, we report on a new inversion technique used to estimate petrophysical formation properties from data acquired by a PWFT. First, a 3D numerical sensitivity study of PWFT data is carried out over a wide range of formation properties including variations of permeability, anisotropy ratio, and porosity. Results from this sensitivity analysis are used as test cases for the inversion algorithm to estimate formation parameters and their uncertainty in the presence of noisy measurements of pressure and flow rate. Inversion is performed making use of a neural network approach. We appraise the robustness and efficiency of the inversion algorithm with actual field data. The estimated formation parameters are further compared to core and wireline data.

Formation-Tester Pulse Testing in Tight Formations (Shales and Heavy Oil): Where Wellbore Storage Effects Favor the Determination of Reservoir Pressure

Tight formation testing when mobilities are lower than 0.01 mD/cP poses significant challenges because the conventional pressure transient buildup testing becomes impractical as a result of the large buildup stabilization time. This paper introduces a new automated pulse test method for testing in tight formations that significantly reduces testing time and makes the determination of formation pressure and permeability possible. A pulse test is defined as a drawdown followed by an injection test, and the source is shut in to record the pressure transient. Based on pressure data during the shut-in period, the next drawdown or injection test is designed, such that the flow rate is a fraction of the initial pulse rate, followed by another shut-in test. This procedure continues until the difference in pressure at the beginning and at the end of the shut-in period is reduced to within a specified limit of pressure change; then, an extended transient is recorded to a stabilized shut-in pressure. The overall advantage is to reduce the pressure stabilization time by implementing an adaptive pressure feedback loop in the system. The method can be applied to a straddle packer test using conventional drillstem testing tools or formation testers, using either straddle packers or probes. The effects of wellbore storage and fluid compressibility are found to reduce the pressure drop and positive pressure pulse in the drawdown and injection tests, respectively; they also affect the decay rate to the asymptote of the shut-in pressure response. Consequently, the combined pulse test method with the pressure feedback system and wellbore storage effect reduces the reservoir pressure testing time in tight formations. The automated pulse-test method has been successfully validated with consideration of the effects of wellbore storage and overbalance pressure in tight gas and heavy oil formations. In addition, the effects of invasion with waterand oil-based mud filtrate were considered in the modeling. The method uses successive pressure feedbacks and automated pulses to yield a pressure to within 0.5% range of the initial reservoir pressure while decreasing the wait time by a factor of 10 for a packer type formation tester. To account for various tool options and storage effects, the packer-type, oval probe, and standard probe-type formation testers have been simulated in various tight formation conditions. The method enables a rapid appraisal of pressure measurements in comparison to conventional testing. Simulations also indicate that the analytical spherical model can be used to analyze a pulse test, even when encountering multi-phase compositional fluid effects. Introduction Important reservoir properties, such as formation pressure and permeability, can be measured with formation-testers (Angeles et al. 2010; Proett et al. 2004; Zazovsky et al. 2005; Elshahawi et al. 1999). Hadibeik et al. (2009 and 2010) tested fluid sampling by means of various probe-type formation testers in laminated reservoirs under the influence of dynamic mudfiltrate invasion. The next advancement in the transient analysis of formation-tester measurements is the consideration of the effect of flowline storage or wellbore storage, which significantly slows down the pressure transient in low mobility formations (Proett et al. 1998; Goode et al. 1987; Yildiz et al. 1991; Chin et al. 2007). Consequently, tight formation testing poses significant challenges when using the conventional drawdown buildup method. Another complication for testing in tight formations is that the measured pressure is supercharged and is greater than the reservoir pressure. The measured shut-in pressure is usually assumed to be the formation pressure. In a permeable formation, mudcake can form quickly and is normally very effective in slowing down invasion and maintaining the wellbore sandface

New Exact Spherical Flow Solution With Storage and Skin for Early-Time Interpretation With Applications to Wireline Formation and Early-Evaluation Drillstem Testing

The wireline formation tester, which is frequently operated over short durations, and a new formation testing tool that obtains pressure measurements during the drilling program, have provided the impetus to develop improved pressure transient analysis methods that support formation evaluation during early-to-intermediate test times. Existing methods, for example, apply to late times only, and are approximate in that they do not model the entire timewise pressure response; alternatively, the detailed models that are available for more exact analysis are numerical, chart-oriented, and not amenable to simple physical interpretation. This paper extends recent work that has solved the spherical flow boundary value problem for storage with an exact analytical solution. Here, the general spherical flow formulation, including both wellbore storage and skin effects, is solved by inverting the complete Laplace transform to produce an exact, closed form, analytical solution. This new solution reduces to previously published early- and late-time solutions in the respective asymptotic limits. However, the new solution permits convenient pressure response to theory matching over the complete time regime (early-, transitional-, and late-time data), rather than conventional late-time, spherical flow matching; it permits critical pressure-transient interpretation using only early-to-intermediate-time data, thereby reducing required rig time. The new solution is derived for the full initial-boundary value problem for transient, compressible, spherical flow using Laplace transforms. Closed-form expressions are obtained for pressure, pressure derivative, and sandface flow rate in terms of complex error functions. These exact solutions are compared to existing spherical solutions obtained by numerical transform inversion, and also to finite element results that include the three-dimensional effects of wellbore geometry. The accuracy and interpretation speed of the new solution permits systematic determination of all flow parameters, to include storage coefficient, skin effect, formation fluid compressibility, permeability, and pore pressure. Its application to a new type of well test tool designed for pressure testing during the drilling program is described. Synthetic data from wireline formation testers and a new drill pipe conveyed pressure test system are analyzed to illustrate the utility and power of the new solution. These examples are used to demonstrate how the new approach can improve real-time regression analysis used in determining formation properties.

Petrophysical Properties of Unconventional Low-Mobility Reservoirs (Shale Gas and Heavy Oil) by Using Newly Developed Adaptive Testing Approach

Pressure testing in very-low-mobility reservoirs is challenging with conventional formation-testing methods. The main difficulty is the over-extended buildup times required to overcome wellbore and formation storage effects. Possible wellbore overbalance or supercharge are additional complicating factors in determining reservoir pressure. This paper addresses the above technical complications and estimates petrophysical properties of low-mobility formations using a newly developed adaptive testing approach. The adaptive testing approach employs an automated pulse-testing method for very-low-mobility reservoirs and uses short drawdowns and injections followed by short pressure stabilization periods. Measured pressure transients are used in an optimized feedback loop to automatically adjust subsequent drawdown and injection pulses in order to reach a stabilized pressure as quickly as possible. The automated pulse data is used to determine supercharge effects, formation pressure and mobility via analytical models by analyzing the entire pressure sequence. A genetic algorithm estimates additional reservoir parameters, such as porosity and viscosity, and confirms results obtained with analytical models (reservoir pressure and permeability). The modeled formation pressure exhibits less than 1% difference with respect to true formation pressure, while the accuracy of other parameters depends on the number of unknown properties. As a faster method to estimate reservoir properties, a direct neural network regression of pulse-testing data was also investigated. Synthetic reservoir models for low-mobility formations (M < 1 D/cp) which included the dynamics of waterand oilbase mud-filtrate invasion that produce wellbore supercharging were developed. These reservoir models simulated the pulsetesting methods, including an automated feedback optimization algorithm that reduces the testing times in a wide range of downhole conditions. The reservoir models included both simulations of underbalanced and overbalanced drilling conditions and enabled the development of new field testing strategies based on a priori reservoir knowledge. The synthetic modeling demonstrates the viability of the new pulse-testing method and confirms that difficult properties, such as supercharging, can be estimated more accurately when coupled with the new inversion techniques. Introduction Formation pressure is a fundamental key to assess the hydrocarbon yield of a reservoir. Without an estimate of the formation pressure, there is a great deal of uncertainty in a field’s development and the investment required. Virtually all the methods used to calculate the net amount of recoverable hydrocarbon are highly dependent on the initial formation pressure (Snyder 1971; Sullivan et al. 1988; Mason 1987; Bennett et al. 1975). Field development optimization also depends on formation pressure estimates to verify reservoir depletion and delineate the producing intervals’ connectivity. There have been attempts to find the fundamental properties of tight sand, shale gas, and heavy oil reservoirs (Dastidar et al. 2007; Abu Omokaro et al. 2011; Shabro et al. 2011; Kundert et al. 2009; Galford et al. 2000). However, rarely reported in literature is a study on the pressure transient analysis methods applied to packer and probe-type formation testing for these types of reservoirs yielding the true formation pressure. When a typical drawdown and buildup test is applied, the pressure transient takes too much buildup time to resolve using conventional analysis or a history match to be of practical value in these very-low-mobility reservoirs. With the introduction of the unconventional automated pulse-test method for lowmobility formations (Hadibeik et al. 2012), it is possible to obtain a pressure response that can be used to determine the initial reservoir pressure and permeability in a practical time frame, usually less than 1 hour. The pressure transient analysis can

Supercharge Pressure Compensation with New Wireline Formation Testing Method

Wireline formation testers are increasingly being used to obtain formation pressure and permeability measurements which in turn are used in geological evaluations and in designing well completions. It is generally assumed that the pressure measured by the tester probe is near formation pressure. Unfortunately, in many instances such as in low permeability formations, the mudcake is not adequate to isolate the hydrostatic pressure from the formation near the wellbore. As a result, the sandface pressure measured with the formation tester is supercharged and not the formation pressure after all. This sandface pressure may be as much as 1,000 psi over the actual formation pressure of interest. This paper demonstrates that a new analytical model can be used along with a new testing technique to correct the measured pressure to actual formation pressure.

New Exact Spherical Flow Solution With Storage for Early-Time Test Interpretation

The objective of an early-pressure-evaluation test (EPE) is to delineate formation pressures and properties quickly over a limited depth scale. Interpreting these tests requires analysis of early-time data in the spherical regime.

Well Test Analysis in the New Economy

This paper provides a chronological history of the evolution of advancement in well testing techniques in order to examine how the technology has progressed to its present state. The first factors examined are those that strongly influenced rechnological development in well-test analysis. The next discussion concerns the problems that still require resolution, and finally, the authors will present what they envision for the future of well-test analysis.