Formation Tester Measurements Research Articles

Assessment of Depth of Mud-Filtrate Invasion and Water Saturation Using Formation-Tester Measurements: Application to Deeply Invaded Tight-Gas Sandstones

Formation pressure/fluid measurements are impacted by mud-filtrate invasion, which may require long fluid pumpout durations to acquire hydrocarbon samples with minimal mud-filtrate contamination. However, unlike other well-logging instruments, formation testers do not have a fixed depth of investigation that limits their ability to pump out mud filtrate until acquiring original formation fluids (i.e., sensing the uninvaded zone). We use an in-house petrophysical and fluid-flow simulator to perform numerical simulations of mud-filtrate invasion, well logs, and formation-tester measurements to estimate the radial distance of invasion and the corresponding radial profile of water saturation. Numerical simulations are initialized with the construction of a multilayer petrophysical model. Initial guesses of volumetric concentration of shale, porosity, water saturation, irreducible water saturation, and residual hydrocarbon saturation are obtained from conventional petrophysical interpretation. Fluid-flow-dependent petrophysical properties (permeability, capillary pressure, and relative permeability), mud properties, rock mineral composition, and in-situ fluid properties are obtained from laboratory measurements. The process of mud-filtrate invasion and the corresponding resistivity and nuclear logs are numerically simulated to iteratively match the available well logs and estimate layer-by-layer formation water saturation. Next, using our multiphase formation testing simulator, we numerically simulate actual fluid sampling operations performed with a dual-packer formation tester. Finally, we estimate irreducible water saturation by minimizing the difference between the hydrocarbon breakthrough time numerically simulated and measured with formation-tester measurements. The examined sandstone reservoir is characterized by low porosity (up to 0.14), low-to-medium permeability (up to 40 md), and high residual gas saturation (between 0.4 and 0.5). The deep mud-filtrate invasion resulted from extended overbalanced exposure to high-salinity water-based mud (17 days of invasion and 1,800 psi overbalance pressure) coupled with the low mud-filtrate storage capacity of tight sandstones. Therefore, the uninvaded formation is located far beyond the depth of investigation of resistivity tools, whereby deep-sensing resistivities are lower than those of uninvaded formation resistivity. Through the numerical simulation of mud-filtrate invasion, well logs, and formation-tester measurements, we estimated radial and vertical distributions of water saturation around the borehole. Likewise, we quantified the hydrocarbon breakthrough time, which matched field measurements of 6.5 hours. The estimated radius of invasion was approximately 2.5 m, while the difference between estimated water saturation in the uninvaded zone and water saturation estimated from the deep-sensing resistivity log was approximately 0.13, therefore improving the estimation of the original gas in place.

Downhole Estimation of Relative Permeability With Integration of Formation-Tester Measurements and Advanced Well Logs

Downhole Estimation of Relative Permeability With Integration of Formation-Tester Measurements and Advanced Well Logs

Streamline-based inversion of formation properties from formation-tester measurements acquired in high-angle and horizontal wells

A new method is developed based on streamlines to determine the reservoir properties from formation-tester measurements. To do so, a previously developed finite-difference reservoir model is coupled with a streamline method to simulate the near-wellbore dynamic measurements in the presence of invasion and arbitrary fluid distributions. The streamline method is specifically developed to overcome technical challenges in modeling deviated wells in heterogeneous reservoirs efficiently. In this study, synthetic reservoir models are constructed based on measurements acquired in offshore well A with 15o deviation angle. The streamline-based method is then implemented to simulate packer-type formation-tester measurements and to appraise permeability of multi-layer reservoirs. In addition, transient measurements from a focused-sampling probe-type formation tester is modeled with streamline method to estimate relative permeability and anisotropy in offshore well B. Inversion results indicate that the accuracy of estimated formation properties is higher for formations with larger mobility because more streamlines trace flow into probes from large-mobility layers. For offshore well A, in the presence of 5% zero-mean Gaussian additive noise, the uncertainty of permeability varies from 6% to 38% for layers with high and low mobilities, respectively. The uncertainty increases to 8% and 41% for high and low mobility cases, respectively, when 5% skewed-Gaussian noise contaminates the measurements. The coupled finite-difference and streamline-based inversion method (FDSM) is then compared to a previously validated finite-difference reservoir model (FDM). The coupled FDSM is 8 times faster than FDM on an average when estimating properties of heterogeneous reservoirs using inversion on formation-tester measurements acquired in highly deviated wells. Computational advantage of FDSM is due to application of one-dimensional solutions of fluid saturations and concentrations along streamlines instead of three-dimensional FDM numerical calculations. Despite the efficiency, history matching of measurements indicates up to 6% difference between FDSM and FDM in results. In high-angle wells, mud-filtrate invasion causes a non-symmetric distribution of invading fluid around the wellbore perimeter. Moreover, presence of large permeability–porosity contrast among layers increases complexity of numerical computations and uncertainty. This study proposes that the streamline-based inversion method is an excellent candidate to overcome these difficulties efficiently.

Evolution of sediment permeability during burial and subduction

AbstractWe assembled a data set of permeability measurements from 317 subduction zone and reference site samples worldwide made over nearly 25 years of scientific drilling. This data set allowed us to examine the influence of grain size, structural domain, and measurement type on permeabilities ranging from 10−21 to 10−14 m2. We found that porosity–permeability behavior is a function of clay‐size fraction, which is consistent with previous work. Sediments within the slope, accretionary prism, and fault‐zone structural domains are strongly affected by shearing, which alters the permeability behavior with burial. Consolidation, flow‐through, and transient pulse decay measurements all provide comparable results. Measurements of horizontal and vertical permeability show significant cm‐scale permeability anisotropy (ratio of horizontal to vertical permeability >10) in the slope and accretionary prism structural domains, further indicating shear deformation in these domains. Laboratory consolidation trends match large‐scale (102 m) field trends in structural domains with negligible shear, but tend to underestimate the rate of permeability reduction with porosity loss where shear is significant. Comparison with downhole measurements shows that permeability is controlled by higher‐permeability (>10−15 m2) layers at the meter to tens of meters scale, while wireline formation tester measurements closely match laboratory results. Sediments from the underthrust and reference structural domains exhibit similar porosity–permeability trends, which suggests that shallow subduction (total burial <1 km) does not significantly alter the porosity–permeability behavior of incoming sediments. Comparison with measurements of deeper analog data from 14 passive‐margin samples show that porosity–permeability trends are maintained through burial and diagenesis to porosities <10%, suggesting that behavior observed in shallow samples is informative for predicting behavior at depth following subduction.

Quantification of the effects of bed lamination and wellbore deviation on the interpretation of formation-tester measurements

Abstract Formation-tester measurements (FTM) acquired in thinly bedded formations and in highly deviated wells often show a large pressure drop during the drawdown period of a pressure-transient test. The measured large pressure drop can be an indication of a low permeability layer at the probe location. We invoke the effects of bed boundaries to explain additional pressure drop in the FTMs. An accurate analysis of the FTMs requires simulating mud-filtrate invasion prior to the pressure-transient test. Specifically, the interplay between gravity, capillary, and viscous forces leads to a highly non-symmetric fluid distribution around the wellbore perimeter in deviated wells. In this condition, it becomes crucial to have depth control and perform fluid sampling at a suitable probe location with respect to the perimeter of the wellbore. A three-dimensional (3D) compositional fluid-flow simulator is employed to simulate mud-filtrate invasion and subsequently FTMs in deviated wells. The simulator is specifically designed for problems where the greatest variations occur in the vicinity of the wellbore. We test the accuracy of the algorithm with a series of drawdown-buildup tests in highly deviated wells; a comparison of results obtained with the available analytical solutions and the numerical simulator shows a very good agreement. Subsequently, using the developed simulator, we study invasion, pressure transient tests after invasion, and fluid sampling after invasion. Results show that invasion in a high-permeability formation causes non-symmetric distribution of fluid around the wellbore of a deviated well. Simulation results confirm that a probe-type FT records significant pressure drops when it is placed at the vertical vicinity of the well; this effect leads to a lower measured permeability compared to the actual permeability. It was also found that pressure drop during drawdown is affected by invasion; pressure drop in invaded formations is greater than in un-invaded formations. We also quantify cleanup time for sampling with a probe-type FT deployed in deviated wells. Results show that the cleanup is achieved faster when the probe is located at the high side of the well.

Sampling with new focused, oval, and conventional probe-type formation-tester in the presence of water- and oil-base mud-filtrate invasion for vertical and high-angle wells

Abstract Speculation about the potential of developing new fluid and pressure sampling methods with probe-type formation testers has existed since the introduction of formation pressure testing while drilling technology was introduced to the industry nearly a decade ago. To replace the existing wireline technology, a new pumping system is required to remove invasion fluids and then to fill single-phase sample chambers. To make this commercially possible, several technology enhancements are necessary in advance. Although wireline pumpout tools may require hours to retrieve representative fluid samples, it is not a practical alternative to spend hours obtaining samples in the drilling environment. Most simulations of wireline formation-tester measurements assumed that invasion ended at the time when fluid pumpout began. Additionally, previous studies assumed a time-constant rate of invasion that was the time average of invasion rate. Both of these assumptions are optimistic for a drilling tool. The objective of this study is to quantify the viability of sampling in the drilling environment by way of numerical simulations. The study considers the dynamic nature of invasion while drilling when using both new and conventional probe configurations to retrieve fluid samples. With the realistic mudcake model, there are higher rates of invasion soon after drilling. Therefore, to simulate the invasion during drilling, a mudcake model is used that continues to grow in thickness and sealing effectiveness during invasion and throughout the sampling process. Simulation results focus on scenarios in which water-base mud (WBM) and oil-base mud (OBM) invade an oil-bearing zone. Furthermore, it studied the accuracy of functions used to estimate contamination in an OBM environment. The base model consists of a typical probe-type tool in a vertical well wherein fluid samples are retrieved using a time-constant flow rate. Invasion time is varied from 1 to 48 h to compare drilling and wireline sampling tools. Simulations of fluid cleanup times for a variety of rock types and wellbore deviation angles indicate that the oval focused probe retrieves the cleanest fluid sample in the least amount of time. This study also quantifies mudcake sealing effectiveness, as well as the effect of borehole deviation. Oval (elongated) and focusing guard-style probes are compared to standard probe configurations in various petrophysical rock types.

Technology Focus: Well Testing (February 2012)

Technology Focus The value of information has a ubiquitous and sometimes pervasive role in modern well testing. From exploration to field management to surveillance, well-test practitioners deal with a wide array of measurements (e.g., pressure, flow rates, temperature, and fluid analysis) that, more often than not, encompass large amounts of data. This is particularly true for long-term-production-data analysis of established fields, and one can argue the same for any current pressure-transient analysis that also has benefited from improved and more-robust data-acquisition available today. Likewise, dynamic information through downhole testing equipment can be acquired in real time—wirelessly and at sampling frequencies that were not possible only a decade ago. Yet what seems to be a relative abundance of data often is challenged by the complex environments in which we operate and by our need to assess its value against associated costs and business risks. One way to look at this is under the premise that, while “perfect” information is beneficial to have, it also is costly to acquire and economically inefficient. Is there a unique answer in our choice of type curves, material balance, or specialized graphs? Should we account for multiphase flow or rock compaction? More importantly, what is the value of the next-best substitute for the information we require? And can this substitute information still allow us to meet our testing objectives? Herein lies the delicate balance between our choices of risk and uncertainty, which brings us to the message of this feature: We should not look for data-rich, but information-rich, content that meets our testing needs. The papers selected for this feature describe exciting advances and opportunities in well testing. They also show that the proper use of advanced techniques can lead to maximizing the value of the information at hand, even in hostile and unconventional situations. Recommended additional reading at OnePetro: www.onepetro.org. SPE 143592 Assessment of Rate-Dependent Skin Factors in Gas-Condensate and Volatile-Oil Wells by A.C. Gringarten, SPE, Imperial College London, et al. SPE 146450 3D Multiphase Streamline-Based Method for Interpretation of Formation-Tester Measurements Acquired in Vertical and Deviated Wells by Hamid Hadibeik, SPE, University of Texas at Austin, et al. SPE 142818 Application of IFOT in Tight Gas as a Reservoir-Surveillance Technique by E. Pinto, BP plc, et al.

Effect of liquid invasion damage and supercharging on wireline formation tester measurements in tight gas reservoirs

Wireline formation testing and measurement of true formation pressure can provide essential knowledge about the reservoir dynamic characteristics. In tight formations, a reliable determination of pressure and mobility gradients is challenging because of the tight nature of formation rock. Due to the very low reservoir permeability, the mud cake across wellbore is often ineffective in preventing filtrate invasion, thus causing the measured pressure to be higher than actual formation pressure as a result of supercharging effect. Wireline formation testing measurements are also influenced by the effects of filtrate invasion and capillary pressure, as the measured pressure is pressure of drilling fluid filtrate, the continuous phase present in the invaded region around wellbore. As a result, the measured pressure might be different to true formation pressure. This effect is more noticeable in tight gas reservoirs due to capillary pressure effect. This paper looks into estimation of true formation pressure and evaluates the effect of filtrate invasion damage and supercharging on wireline formation tester measurements in tight gas reservoirs. Numerical simulation approach is used to build the reservoir model based on data acquired from a tight gas reservoir. The model undergoes water injection followed by gas production from different testing points along the wellbore, and the corresponding pressure gradients are plotted to check for pressure matching with that of the formation fluid in the virgin region. The results indicate the significant effects of supercharging, reservoir characteristics, capillary pressure and liquid invasion damage on wireline formation pressure measurements in tight gas reservoirs.

Estimation of capillary pressure and relative permeability from formation-tester measurements using Design of Experiment and data-weighing inversion: Synthetic and field examples

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 flow-rate measurements acquired with formation testers. However, such procedures are still unclear to many practicing analysts and to date have not been fully explored with either synthetic or field data.This paper presents the development and field test of a new method to estimate saturation-dependent rock properties. The two data sets considered in our examples use in-house and commercial reservoir simulators to model the processes of mud-filtrate invasion, acquisition of borehole resistivity measurements, and subsequent fluid withdrawal during formation tester sampling. Capillary pressure and relative permeability are described using the Brooks–Corey model comprised of 6 independent unknown parameters. The iterative procedure repeats itself until measurements are all honored within prescribed error bounds. As a result, the estimation method satisfactorily reconstructs the relative permeability and capillary pressure curves with minimal a-priori information. Whereas relative permeability end-points of water and oil can be readily estimated in a couple of non-linear iterations (assuming that the remaining parameters are fixed), residual and irreducible saturations add complexity to the inversion. We also investigate the use of Design of Experiment (DoE) tools to secure a reliable initial guess for nonlinear inversion and to understand the separate contributions of the various measurements to specific inversion parameters. Such information is fundamental in the design of a data-weighing scheme that selectively enhances the sensitivity of the measurements to unknown parameters during progressive steps of nonlinear inversion.

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

Summary 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 processes of mudcake buildup and invasion. An efficient 2D (cylindrical coordinates) implicit-pressure explicit-saturation finite-difference 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 nonuniqueness 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. Applications of the inversion method to noisy synthetic measurements include homogeneous, anisotropic, single and multilayer formations for cases of low- and high-permeability rocks. We also study the effect of unaccounted impermeable bed boundaries on inverted formation properties. For cases where a priori information can be sufficiently constrained, our inversion methodology provides reliable and accurate estimates of permeability and permeability anisotropy. In addition, we show that estimation errors of permeability inversion procedures that neglect the physics of two-phase immiscible fluid flow and mud-filtrate invasion can be as high as 100%.

Axially symmetric compositional simulation of formation tester measurements

This paper describes the development, testing, and successful application of a new compositional code for the numerical simulation of oil-based mud invasion and formation tester measurements that involve arbitrary miscibility between oil-based mud and native oil. The simulator assumes axially symmetric variations of petrophysical properties as well as axially symmetric flow-rate sources and boundary conditions. However, there are no restricting assumptions to the degree of miscibility between the fluids involved in the simulations. We solve the time–space evolution of component concentration with a time-marching implicit pressure explicit concentration (IMPEC) scheme. This method of solution considers the complete equations of state and implements flash calculations to describe the thermo-dynamical evolution of the various compositional phases due to space–time variations of pressure and concentration. Simulations described in this paper consider the process of oil-based mud–filtrate invasion into reservoirs containing mixtures of connate water and oil. Subsequently, we simulate formation tester measurements by enforcing fluid withdrawal through the dual-packer section of the tester. Measurements consist of fluid pressure, fractional flow rates, fluid density, and fluid viscosity. Examples of application include homogenous and multi-layer formations as well as a capillary transition zone. Comparison of simulation results against those obtained with a commercial code confirms the efficiency, accuracy, and reliability of our method of solution. Sensitivity analysis indicate that time evolution of fractional flow rates, fluid density, and fluid viscosity measured with the formation tester remain influenced by the petrophysical properties of the formation, volume of mud–filtrate invasion, and by saturation-dependent rock–fluid properties (relative permeability and capillary pressure). The simulations described in this paper provide suitable guidelines for the acquisition of clean samples of in-situ formation fluids in the presence of invasion and heterogeneous conditions of petrophysical and rock–fluid properties.